[Title 30 CFR ]
[Code of Federal Regulations (annual edition) - July 1, 2018 Edition]
[From the U.S. Government Publishing Office]

[[Page i]]

Title 30

Mineral Resources

________________________

Parts 200 to 699

Revised as of July 1, 2018

Containing a codification of documents of general
applicability and future effect

As of July 1, 2018
Published by the Office of the Federal Register
National Archives and Records Administration as a
Special Edition of the Federal Register

[[Page ii]]

U.S. GOVERNMENT OFFICIAL EDITION NOTICE

Legal Status and Use of Seals and Logos

The seal of the National Archives and Records Administration
(NARA) authenticates the Code of Federal Regulations (CFR) as
the official codification of Federal regulations established
under the Federal Register Act. Under the provisions of 44
U.S.C. 1507, the contents of the CFR, a special edition of the
Federal Register, shall be judicially noticed. The CFR is
prima facie evidence of the original documents published in
the Federal Register (44 U.S.C. 1510).

It is prohibited to use NARA's official seal and the stylized Code
of Federal Regulations logo on any republication of this
material without the express, written permission of the
Archivist of the United States or the Archivist's designee.
Any person using NARA's official seals and logos in a manner
inconsistent with the provisions of 36 CFR part 1200 is
subject to the penalties specified in 18 U.S.C. 506, 701, and
1017.

Use of ISBN Prefix

This is the Official U.S. Government edition of this publication
and is herein identified to certify its authenticity. Use of
the 0-16 ISBN prefix is for U.S. Government Publishing Office
Official Editions only. The Superintendent of Documents of the
U.S. Government Publishing Office requests that any reprinted
edition clearly be labeled as a copy of the authentic work
with a new ISBN.

U . S . G O V E R N M E N T P U B L I S H I N G O F F I C E

------------------------------------------------------------------

U.S. Superintendent of Documents Washington, DC
20402-0001

http://bookstore.gpo.gov

Phone: toll-free (866) 512-1800; DC area (202) 512-1800

[[Page iii]]

Table of contents

Page
Explanation................................................. v

Title 30:
Chapter II--Bureau of Safety and Environmental
Enforcement, Department of the Interior 3
Chapter IV--Geological Survey, Department of the
Interior 335
Chapter V--Bureau of Ocean Energy Management,
Department of the Interior 347
Finding Aids:
Table of CFR Titles and Chapters........................ 635
Alphabetical List of Agencies Appearing in the CFR...... 655
List of CFR Sections Affected........................... 665

[[Page iv]]

----------------------------

Cite this Code: CFR
To cite the regulations in
this volume use title,
part and section number.
Thus, 30 CFR 203.0 refers
to title 30, part 203,
section 0.

----------------------------

[[Page v]]

EXPLANATION

The Code of Federal Regulations is a codification of the general and
permanent rules published in the Federal Register by the Executive
departments and agencies of the Federal Government. The Code is divided
into 50 titles which represent broad areas subject to Federal
regulation. Each title is divided into chapters which usually bear the
name of the issuing agency. Each chapter is further subdivided into
parts covering specific regulatory areas.
Each volume of the Code is revised at least once each calendar year
and issued on a quarterly basis approximately as follows:

Title 1 through Title 16.................................as of January 1
Title 17 through Title 27..................................as of April 1
Title 28 through Title 41...................................as of July 1
Title 42 through Title 50................................as of October 1

The appropriate revision date is printed on the cover of each
volume.

LEGAL STATUS

The contents of the Federal Register are required to be judicially
noticed (44 U.S.C. 1507). The Code of Federal Regulations is prima facie
evidence of the text of the original documents (44 U.S.C. 1510).

HOW TO USE THE CODE OF FEDERAL REGULATIONS

The Code of Federal Regulations is kept up to date by the individual
issues of the Federal Register. These two publications must be used
together to determine the latest version of any given rule.
To determine whether a Code volume has been amended since its
revision date (in this case, July 1, 2018), consult the ``List of CFR
Sections Affected (LSA),'' which is issued monthly, and the ``Cumulative
List of Parts Affected,'' which appears in the Reader Aids section of
the daily Federal Register. These two lists will identify the Federal
Register page number of the latest amendment of any given rule.

EFFECTIVE AND EXPIRATION DATES

Each volume of the Code contains amendments published in the Federal
Register since the last revision of that volume of the Code. Source
citations for the regulations are referred to by volume number and page
number of the Federal Register and date of publication. Publication
dates and effective dates are usually not the same and care must be
exercised by the user in determining the actual effective date. In
instances where the effective date is beyond the cut-off date for the
Code a note has been inserted to reflect the future effective date. In
those instances where a regulation published in the Federal Register
states a date certain for expiration, an appropriate note will be
inserted following the text.

OMB CONTROL NUMBERS

The Paperwork Reduction Act of 1980 (Pub. L. 96-511) requires
Federal agencies to display an OMB control number with their information
collection request.

[[Page vi]]

Many agencies have begun publishing numerous OMB control numbers as
amendments to existing regulations in the CFR. These OMB numbers are
placed as close as possible to the applicable recordkeeping or reporting
requirements.

PAST PROVISIONS OF THE CODE

Provisions of the Code that are no longer in force and effect as of
the revision date stated on the cover of each volume are not carried.
Code users may find the text of provisions in effect on any given date
in the past by using the appropriate List of CFR Sections Affected
(LSA). For the convenience of the reader, a ``List of CFR Sections
Affected'' is published at the end of each CFR volume. For changes to
the Code prior to the LSA listings at the end of the volume, consult
previous annual editions of the LSA. For changes to the Code prior to
2001, consult the List of CFR Sections Affected compilations, published
for 1949-1963, 1964-1972, 1973-1985, and 1986-2000.

``[RESERVED]'' TERMINOLOGY

The term ``[Reserved]'' is used as a place holder within the Code of
Federal Regulations. An agency may add regulatory information at a
``[Reserved]'' location at any time. Occasionally ``[Reserved]'' is used
editorially to indicate that a portion of the CFR was left vacant and
not accidentally dropped due to a printing or computer error.

INCORPORATION BY REFERENCE

What is incorporation by reference? Incorporation by reference was
established by statute and allows Federal agencies to meet the
requirement to publish regulations in the Federal Register by referring
to materials already published elsewhere. For an incorporation to be
valid, the Director of the Federal Register must approve it. The legal
effect of incorporation by reference is that the material is treated as
if it were published in full in the Federal Register (5 U.S.C. 552(a)).
This material, like any other properly issued regulation, has the force
of law.
What is a proper incorporation by reference? The Director of the
Federal Register will approve an incorporation by reference only when
the requirements of 1 CFR part 51 are met. Some of the elements on which
approval is based are:
(a) The incorporation will substantially reduce the volume of
material published in the Federal Register.
(b) The matter incorporated is in fact available to the extent
necessary to afford fairness and uniformity in the administrative
process.
(c) The incorporating document is drafted and submitted for
publication in accordance with 1 CFR part 51.
What if the material incorporated by reference cannot be found? If
you have any problem locating or obtaining a copy of material listed as
an approved incorporation by reference, please contact the agency that
issued the regulation containing that incorporation. If, after
contacting the agency, you find the material is not available, please
notify the Director of the Federal Register, National Archives and
Records Administration, 8601 Adelphi Road, College Park, MD 20740-6001,
or call 202-741-6010.

CFR INDEXES AND TABULAR GUIDES

A subject index to the Code of Federal Regulations is contained in a
separate volume, revised annually as of January 1, entitled CFR Index
and Finding Aids. This volume contains the Parallel Table of Authorities
and Rules. A list of CFR titles, chapters, subchapters, and parts and an
alphabetical list of agencies publishing in the CFR are also included in
this volume.

[[Page vii]]

An index to the text of ``Title 3--The President'' is carried within
that volume.
The Federal Register Index is issued monthly in cumulative form.
This index is based on a consolidation of the ``Contents'' entries in
the daily Federal Register.
A List of CFR Sections Affected (LSA) is published monthly, keyed to
the revision dates of the 50 CFR titles.

REPUBLICATION OF MATERIAL

There are no restrictions on the republication of material appearing
in the Code of Federal Regulations.

INQUIRIES

For a legal interpretation or explanation of any regulation in this
volume, contact the issuing agency. The issuing agency's name appears at
the top of odd-numbered pages.
For inquiries concerning CFR reference assistance, call 202-741-6000
or write to the Director, Office of the Federal Register, National
Archives and Records Administration, 8601 Adelphi Road, College Park, MD
20740-6001 or e-mail [email protected].

SALES

The Government Publishing Office (GPO) processes all sales and
distribution of the CFR. For payment by credit card, call toll-free,
866-512-1800, or DC area, 202-512-1800, M-F 8 a.m. to 4 p.m. e.s.t. or
fax your order to 202-512-2104, 24 hours a day. For payment by check,
write to: US Government Publishing Office - New Orders, P.O. Box 979050,
St. Louis, MO 63197-9000.

ELECTRONIC SERVICES

The full text of the Code of Federal Regulations, the LSA (List of
CFR Sections Affected), The United States Government Manual, the Federal
Register, Public Laws, Public Papers of the Presidents of the United
States, Compilation of Presidential Documents and the Privacy Act
Compilation are available in electronic format via www.govinfo.gov. For
more information, contact the GPO Customer Contact Center, U.S.
Government Publishing Office. Phone 202-512-1800, or 866-512-1800 (toll-
free). E-mail, [email protected].
The Office of the Federal Register also offers a free service on the
National Archives and Records Administration's (NARA) World Wide Web
site for public law numbers, Federal Register finding aids, and related
information. Connect to NARA's web site at www.archives.gov/federal-
register.
The e-CFR is a regularly updated, unofficial editorial compilation
of CFR material and Federal Register amendments, produced by the Office
of the Federal Register and the Government Publishing Office. It is
available at www.ecfr.gov.

Oliver A. Potts,
Director,
Office of the Federal Register
July 1, 2018

[[Page ix]]

THIS TITLE

Title 30--Mineral Resources is composed of three volumes. The parts
in these volumes are arranged in the following order: parts 1--199,
parts 200--699, and part 700 to end. The contents of these volumes
represent all current regulations codified under this title of the CFR
as of July 1, 2018.

For this volume, Cheryl E. Sirofchuck was Chief Editor. The Code of
Federal Regulations publication program is under the direction of John
Hyrum Martinez, assisted by Stephen J. Frattini.

[[Page 1]]

TITLE 30--MINERAL RESOURCES

(This book contains parts 200 to 699)

--------------------------------------------------------------------
Part

chapter ii--Bureau of Safety and Environmental Enforcement,
Department of the Interior................................ 203

chapter iv--Geological Survey, Department of the Interior... 401

chapter v--Bureau of Ocean Energy Management, Department of
the Interior.............................................. 519

[[Page 3]]

CHAPTER II--BUREAU OF SAFETY AND ENVIRONMENTAL ENFORCEMENT, DEPARTMENT
OF THE INTERIOR

--------------------------------------------------------------------

SUBCHAPTER A--MINERALS REVENUE MANAGEMENT
Part Page
200-202

[Reserved]

203 Relief or reduction in royalty rates........ 5
219

[Reserved]

SUBCHAPTER B--OFFSHORE
250 Oil and gas and sulphur operations in the
Outer Continental Shelf................. 44
251 Geological and geophysical (G&G)
explorations of the Outer Continental
Shelf................................... 286
252 Outer Continental Shelf (OCS) Oil and Gas
Information Program..................... 291
253

[Reserved]

254 Oil-spill response requirements for
facilities located seaward of the coast
line.................................... 296
256 Leasing of sulphur or oil and gas in the
Outer Continental Shelf................. 311
259-260

[Reserved]

270 Nondiscrimination in the Outer Continental
Shelf................................... 313
280 Prospecting for minerals other than oil,
gas, and sulphur on the Outer
Continental Shelf....................... 315
281

[Reserved]

282 Operations in the Outer Continental Shelf
for minerals other than oil, gas, and
sulphur................................. 316
285

[Reserved]

SUBCHAPTER C--APPEALS
290 Appeal procedures........................... 327
291 Open and nondiscriminatory access to oil and
gas pipelines under the Outer
Continental Shelf Lands Act............. 328
292-299

[Reserved]

[[Page 5]]

SUBCHAPTER A_MINERALS REVENUE MANAGEMENT

PARTS 200 202 [RESERVED]

PART 203_RELIEF OR REDUCTION IN ROYALTY RATES--Table of Contents

Subpart A_General Provisions

Sec.
203.0 What definitions apply to this part?
203.1 What is BSEE's authority to grant royalty relief?
203.2 How can I obtain royalty relief?
203.3 Do I have to pay a fee to request royalty relief?
203.4 How do the provisions in this part apply to different types of
leases and projects?
203.5 What is BSEE's authority to collect information?

Subpart B_OCS Oil, Gas, and Sulfur General

Royalty Relief for Drilling Ultra-Deep Wells on Leases Not Subject to
Deep Water Royalty Relief

203.30 Which leases are eligible for royalty relief as a result of
drilling a phase 2 or phase 3 ultra-deep well?
203.31 If I have a qualified phase 2 or qualified phase 3 ultra-deep
well, what royalty relief would that well earn for my lease?
203.32 What other requirements or restrictions apply to royalty relief
for a qualified phase 2 or phase 3 ultra-deep well?
203.33 To which production do I apply the RSV earned by qualified phase
2 and phase 3 ultra-deep wells on my lease or in my unit?
203.34 To which production may an RSV earned by qualified phase 2 and
phase 3 ultra-deep wells on my lease not be applied?
203.35 What administrative steps must I take to use the RSV earned by a
qualified phase 2 or phase 3 ultra-deep well?
203.36 Do I keep royalty relief if prices rise significantly?

Royalty Relief for Drilling Deep Gas Wells on Leases Not Subject to Deep
Water Royalty Relief

203.40 Which leases are eligible for royalty relief as a result of
drilling a deep well or a phase 1 ultra-deep well?
203.41 If I have a qualified deep well or a qualified phase 1 ultra-deep
well, what royalty relief would my lease earn?
203.42 What conditions and limitations apply to royalty relief for deep
wells and phase 1 ultra-deep wells?
203.43 To which production do I apply the RSV earned from qualified deep
wells or qualified phase 1 ultra-deep wells on my lease?
203.44 What administrative steps must I take to use the royalty
suspension volume?
203.45 If I drill a certified unsuccessful well, what royalty relief
will my lease earn?
203.46 To which production do I apply the royalty suspension supplements
from drilling one or two certified unsuccessful wells on my
lease?
203.47 What administrative steps do I take to obtain and use the royalty
suspension supplement?
203.48 Do I keep royalty relief if prices rise significantly?
203.49 May I substitute the deep gas drilling provisions in this part
for the deep gas royalty relief provided in my lease terms?

Royalty Relief for End-of-Life Leases

203.50 Who may apply for end-of-life royalty relief?
203.51 How do I apply for end-of-life royalty relief?
203.52 What criteria must I meet to get relief?
203.53 What relief will BSEE grant?
203.54 How does my relief arrangement for an oil and gas lease operate
if prices rise sharply?
203.55 Under what conditions can my end-of-life royalty relief
arrangement for an oil and gas lease be ended?
203.56 Does relief transfer when a lease is assigned?

Royalty Relief for Pre-Act Deep Water Leases and for Development and
Expansion Projects

203.60 Who may apply for royalty relief on a case-by-case basis in deep
water in the Gulf of Mexico or offshore of Alaska?
203.61 How do I assess my chances for getting relief?
203.62 How do I apply for relief?
203.63 Does my application have to include all leases in the field?
203.64 How many applications may I file on a field or a development
project?
203.65 How long will BSEE take to evaluate my application?
203.66 What happens if BSEE does not act in the time allowed?
203.67 What economic criteria must I meet to get royalty relief on an
authorized field or project?
203.68 What pre-application costs will BSEE consider in determining
economic viability?

[[Page 6]]

203.69 If my application is approved, what royalty relief will I
receive?
203.70 What information must I provide after BSEE approves relief?
203.71 How does BSEE allocate a field's suspension volume between my
lease and other leases on my field?
203.72 Can my lease receive more than one suspension volume?
203.73 How do suspension volumes apply to natural gas?
203.74 When will BSEE reconsider its determination?
203.75 What risk do I run if I request a redetermination?
203.76 When might BSEE withdraw or reduce the approved size of my
relief?
203.77 May I voluntarily give up relief if conditions change?
203.78 Do I keep relief approved by BSEE under this part for my lease,
unit or project if prices rise significantly?
203.79 How do I appeal BSEE's decisions related to royalty relief for a
deepwater lease or a development or expansion project?
203.80 When can I get royalty relief if I am not eligible for royalty
relief under other sections in the subpart?

Required Reports

203.81 What supplemental reports do royalty-relief applications require?
203.82 What is BSEE's authority to collect this information?
203.83 What is in an administrative information report?
203.84 What is in a net revenue and relief justification report?
203.85 What is in an economic viability and relief justification report?
203.86 What is in a G&G report?
203.87 What is in an engineering report?
203.88 What is in a production report?
203.89 What is in a cost report?
203.90 What is in a fabricator's confirmation report?
203.91 What is in a post-production development report?

Subpart C--Federal and Indian Oil [Reserved]

Subpart D--Federal and Indian Gas [Reserved]

Subpart E--Solid Minerals, General [Reserved]

Subpart F [Reserved]

Subpart G--Other Solid Minerals [Reserved]

Subpart H--Geothermal Resources [Reserved]

Subpart I--OCS Sulfur [Reserved]

Authority: 25 U.S.C. 396 et seq.; 25 U.S.C. 396a et seq.; 25 U.S.C.
2101 et seq.; 30 U.S.C. 181 et seq.; 30 U.S.C. 351 et seq.; 30 U.S.C.
1001 et seq.; 30 U.S.C. 1701 et seq.; 31 U.S.C. 9701; 42 U.S.C. 15903-
15906; 43 U.S.C. 1301 et seq.; 43 U.S.C. 1331 et seq.; and 43 U.S.C.
1801 et seq.

Source: 76 FR 64462, Oct. 18, 2011, unless otherwise noted.

Subpart A_General Provisions

Sec. 203.0 What definitions apply to this part?

Authorized field means a field:
(1) Located in a water depth of at least 200 meters and in the Gulf
of Mexico (GOM) west of 87 degrees, 30 minutes West longitude;
(2) That includes one or more pre-Act leases; and
(3) From which no current pre-Act lease produced, other than test
production, before November 28, 1995.
Certified unsuccessful well means an original well or a sidetrack
with a sidetrack measured depth (i.e., length) of at least 10,000 feet,
on your lease that:
(1) You begin drilling on or after March 26, 2003, and before May 3,
2009, on a lease that is located in water partly or entirely less than
200 meters deep and that is not a non-converted lease, or on or after
May 18, 2007, and before May 3, 2013, on a lease that is located in
water entirely more than 200 meters and entirely less than 400 meters
deep;
(2) You begin drilling before your lease produces gas or oil from a
well with a perforated interval the top of which is at least 18,000 feet
true vertical depth subsea (TVD SS), (i.e., below the datum at mean sea
level);
(3) You drill to at least 18,000 feet TVD SS with a target reservoir
on your lease, identified from seismic and related data, deeper than
that depth;
(4) Fails to meet the producibility requirements of 30 CFR part 550,
subpart A, and does not produce gas or oil, or meets those producibility
requirements and Bureau of Ocean Energy Management (BOEM) agrees it is
not commercially producible; and
(5) For which you have provided the notices and information required
under Sec. 203.47.

[[Page 7]]

Complete application means an original and two copies of the six
reports consisting of the data specified in Sec. Sec. 203.81, 203.83,
and 203.85 through 203.89, along with one set of digital information,
which Bureau of Safety and Environmental Enforcement (BSEE) has reviewed
and found complete.
Deep well means either an original well or a sidetrack with a
perforated interval the top of which is at least 15,000 feet TVD SS and
less than 20,000 feet TVD SS. A deep well subsequently re-perforated at
less than 15,000 feet TVD SS in the same reservoir is still a deep well.
Determination means the binding decision by BSEE on whether your
field qualifies for relief or how large a royalty-suspension volume must
be to make the field economically viable.
Development project means a project to develop one or more oil or
gas reservoirs located on one or more contiguous leases that have had no
production (other than test production) before the current application
for royalty relief and are either:
(1) Located in a planning area offshore Alaska; or
(2) Located in the GOM in a water depth of at least 200 meters and
wholly west of 87 degrees, 30 minutes West longitude, and were issued in
a sale held after November 28, 2000.
Draft application means the preliminary set of information and
assumptions you submit to seek a nonbinding assessment on whether a
field could be expected to qualify for royalty relief.
Eligible lease means a lease that:
(1) Is issued as part of an OCS lease sale held after November 28,
1995, and before November 28, 2000;
(2) Is located in the Gulf of Mexico in water depths of 200 meters
or deeper;
(3) Lies wholly west of 87 degrees, 30 minutes West longitude; and
(4) Is offered subject to a royalty suspension volume.
Expansion project means a project that meets the following
requirements:
(1) You must propose the project in a (BOEM) Development and
Production Plan, a BOEM Development Operations Coordination Document
(DOCD), or a BOEM Supplement to a DOCD, approved by the Secretary of the
Interior after November 28, 1995.
(2) The project must be located on either:
(i) A pre-Act lease in the GOM, or a lease in the GOM issued in a
sale held after November 28, 2000, located wholly west of 87 degrees, 30
minutes West longitude; or
(ii) A lease in a planning area offshore Alaska.
(3) On a pre-Act lease in the GOM, the project:
(i) Must significantly increase the ultimate recovery of resources
from one or more reservoirs that have not previously produced (extending
recovery from reservoirs already in production does not constitute a
significant increase); and
(ii) Must involve a substantial capital investment (e.g., fixed-leg
platform, subsea template and manifold, tension-leg platform, multiple
well project, etc.).
(4) For a lease issued in a planning area offshore Alaska, or in the
GOM after November 28, 2000, the project must involve a new well drilled
into a reservoir that has not previously produced.
(5) On a lease in the GOM, the project must not include a reservoir
the production from which an RSV under Sec. Sec. 203.30 through 203.36
or Sec. Sec. 203.40 through 203.48 would be applied.
Fabrication (or start of construction) means evidence of an
irreversible commitment to a concept and scale of development. Evidence
includes copies of a binding contract between you (as applicant) and a
fabrication yard, a letter from a fabricator certifying that continuous
construction has begun, and a receipt for the customary down payment.
Field means an area consisting of a single reservoir or multiple
reservoirs all grouped on, or related to, the same general geological
structural feature or stratigraphic trapping condition. Two or more
reservoirs may be in a field, separated vertically by intervening
impervious strata or laterally by local geologic barriers, or both.
Lease means a lease or unit.
New production means any production from a current pre-Act lease
from which no royalties are due on production, other than test
production, before November 28, 1995. Also, it means any

[[Page 8]]

additional production resulting from new lease-development activities on
a lease issued in a sale after November 28, 2000, or a current pre-Act
lease under a BOEM DOCD or a BOEM Supplement approved by the Secretary
of the Interior after November 28, 1995.
Nonbinding assessment means an opinion by BSEE of whether your field
could qualify for royalty relief. It is based on your draft application
and does not entitle the field to relief.
Non-converted lease means a lease located partly or entirely in
water less than 200 meters deep issued in a lease sale held after
January 1, 2001, and before January 1, 2004, whose original lease terms
provided for an RSV for deep gas production and the lessee has not
exercised the option under Sec. 203.49 to replace the lease terms for
royalty relief with those in Sec. 203.0 and Sec. Sec. 203.40 through
203.48.
Original well means a well that is drilled without utilizing an
existing wellbore. An original well includes all sidetracks drilled from
the original wellbore either before the drilling rig moves off the well
location or after a temporary rig move that BSEE agrees was forced by a
weather or safety threat and drilling resumes within 1 year. A bypass
from an original well (e.g., drilling around material blocking the hole
or to straighten crooked holes) is part of the original well.
Participating area means that part of the unit area that BSEE
determines is reasonably proven by drilling and completion of producible
wells, geological and geophysical information, and engineering data to
be capable of producing hydrocarbons in paying quantities.
Performance conditions mean minimum conditions you must meet, after
we have granted relief and before production begins, to remain qualified
for that relief. If you do not meet each one of these performance
conditions, we consider it a change in material fact significant enough
to invalidate our original evaluation and approval.
Phase 1 ultra-deep well means an ultra-deep well on a lease that is
located in water partly or entirely less than 200 meters deep for which
drilling began before May 18, 2007, and that begins production before
May 3, 2009, or that meets the requirements to be a certified
unsuccessful well.
Phase 2 ultra-deep well means an ultra-deep well for which drilling
began on or after May 18, 2007; and that either meets the requirements
to be a certified unsuccessful well or that begins production:
(1) Before the date which is 5 years after the lease issuance date
on a non-converted lease; or
(2) Before May 3, 2009, on all other leases located in water partly
or entirely less than 200 meters deep; or
(3) Before May 3, 2013, on a lease that is located in water entirely
more than 200 meters and entirely less than 400 meters deep.
Phase 3 ultra-deep well means an ultra-deep well for which drilling
began on or after May 18, 2007, and that begins production:
(1) On or after the date which is 5 years after the lease issuance
date on a non-converted lease; or
(2) On or after May 3, 2009, on all other leases located in water
partly or entirely less than 200 meters deep; or
(3) On or after May 3, 2013, on a lease that is located in water
entirely more than 200 meters and entirely less than 400 meters deep.
Pre-Act lease means a lease that:
(1) Results from a sale held before November 28, 1995;
(2) Is located in the GOM in water depths of 200 meters or deeper;
and
(3) Lies wholly west of 87 degrees, 30 minutes West longitude.
Production means all oil, gas, and other relevant products you save,
remove, or sell from a tract or those quantities allocated to your tract
under a unitization formula, as measured for the purposes of determining
the amount of royalty payable to the United States.
Project means any activity that requires at least a permit to drill.
Qualified deep well means:
(1) On a lease that is located in water partly or entirely less than
200 meters deep that is not a non-converted lease, a deep well for which
drilling began on or after March 26, 2003, that produces natural gas
(other than test production), including gas associated with oil
production, before May 3, 2009, and for

[[Page 9]]

which you have met the requirements prescribed in Sec. 203.44;
(2) On a non-converted lease, a deep well that produces natural gas
(other than test production) before the date which is 5 years after the
lease issuance date from a reservoir that has not produced from a deep
well on any lease; or
(3) On a lease that is located in water entirely more than 200
meters but entirely less than 400 meters deep, a deep well for which
drilling began on or after May 18, 2007, that produces natural gas
(other than test production), including gas associated with oil
production before May 3, 2013, and for which you have met the
requirements prescribed in Sec. 203.44.
Qualified ultra-deep well means:
(1) On a lease that is located in water partly or entirely less than
200 meters deep that is not a non-converted lease, an ultra-deep well
for which drilling began on or after March 26, 2003, that produces
natural gas (other than test production), including gas associated with
oil production, and for which you have met the requirements prescribed
in Sec. 203.35 or Sec. 203.44, as applicable; or
(2) On a lease that is located in water entirely more than 200
meters and entirely less than 400 meters deep, or on a non-converted
lease, an ultra-deep well for which drilling began on or after May 18,
2007, that produces natural gas (other than test production), including
gas associated with oil production, and for which you have met the
requirements prescribed in Sec. 203.35.
Qualified well means either a qualified deep well or a qualified
ultra-deep well.
Redetermination means our reconsideration of our determination on
royalty relief because you request it after:
(1) We have rejected your application;
(2) We have granted relief but you want a larger suspension volume;
(3) We withdraw approval; or
(4) You renounce royalty relief.
Renounce means action you take to give up relief after we have
granted it and before you start production.
Reservoir means an underground accumulation of oil or natural gas,
or both, characterized by a single pressure system and segregated from
other such accumulations.
Royalty suspension (RS) lease means a lease that:
(1) Is issued as part of an OCS lease sale held after November 28,
2000;
(2) Is in locations or planning areas specified in a particular
Notice of OCS Lease Sale offering that lease; and
(3) Is offered subject to a royalty suspension specified in a Notice
of OCS Lease Sale published in the Federal Register.
Royalty suspension supplement (RSS) means a royalty suspension
volume resulting from drilling a certified unsuccessful well that is
applied to future natural gas and oil production generated at any
drilling depth on, or allocated under a BSEE-approved unit agreement to,
the same lease.
Royalty suspension volume (RSV) means a volume of production from a
lease that is not subject to royalty under the provisions of this part.
Sidetrack means, for the purpose of this subpart, a well resulting
from drilling an additional hole to a new objective bottom-hole location
by leaving a previously drilled hole. A sidetrack also includes drilling
a well from a platform slot reclaimed from a previously drilled well or
re-entering and deepening a previously drilled well. A bypass from a
sidetrack (e.g., drilling around material blocking the hole, or to
straighten crooked holes) is part of the sidetrack.
Sidetrack measured depth means the actual distance or length in feet
a sidetrack is drilled beginning where it exits a previously drilled
hole to the bottom hole of the sidetrack, that is, to its total depth.
Sunk costs for an authorized field means the after-tax eligible
costs that you (not third parties) incur for exploration, development,
and production from the spud date of the first discovery on the field to
the date we receive your complete application for royalty relief. The
discovery well must be qualified as producible under 30 CFR part 550,
subpart A. Sunk costs include the rig mobilization and material costs
for the discovery well that you incurred before its spud date.

[[Page 10]]

Sunk costs for an expansion or development project means the after-
tax eligible costs that you (not third parties) incur for only the first
well that encounters hydrocarbons in the reservoir(s) included in the
application and that meets the producibility requirements under 30 CFR
part 550, subpart A on each lease participating in the application. Sunk
costs include rig mobilization and material costs for the discovery
wells that you incurred before their spud dates.
Ultra-deep well means either an original well or a sidetrack
completed with a perforated interval the top of which is at least 20,000
feet TVD SS. An ultra-deep well subsequently re-perforated less than
20,000 feet TVD SS in the same reservoir is still an ultra-deep well.
Withdraw means action we take on a field that has qualified for
relief if you have not met one or more of the performance conditions.

Sec. 203.1 What is BSEE's authority to grant royalty relief?

The Outer Continental Shelf (OCS) Lands Act, 43 U.S.C. 1337, as
amended by the OCS Deep Water Royalty Relief Act (DWRRA), Public Law
104-58 and the Energy Policy Act of 2005, Public Law 109-058 authorizes
us to grant royalty relief in four situations.
(a) Under 43 U.S.C. 1337(a)(3)(A), we may reduce or eliminate any
royalty or a net profit share specified for an OCS lease to promote
increased production.
(b) Under 43 U.S.C. 1337(a)(3)(B), we may reduce, modify, or
eliminate any royalty or net profit share to promote development,
increase production, or encourage production of marginal resources on
certain leases or categories of leases. This authority is restricted to
leases in the GOM that are west of 87 degrees, 30 minutes West
longitude, and in the planning areas offshore Alaska.
(c) Under 43 U.S.C. 1337(a)(3)(C), we may suspend royalties for
designated volumes of new production from any lease if:
(1) Your lease is in deep water (water at least 200 meters deep);
(2) Your lease is in designated areas of the GOM (west of 87
degrees, 30 minutes West longitude);
(3) Your lease was acquired in a lease sale held before the DWRRA
(before November 28, 1995);
(4) We find that your new production would not be economic without
royalty relief; and
(5) Your lease is on a field that did not produce before enactment
of the DWRRA, or if you propose a project to significantly expand
production under a Development Operations Coordination Document (DOCD)
or a supplementary DOCD, that the Bureau of Ocean Energy Management
(BOEM) approved after November 28, 1995.
(d) Under 42 U.S.C. 15904-15905, we may suspend royalties for
designated volumes of gas production from deep and ultra-deep wells on a
lease if:
(1) Your lease is in shallow water (water less than 400 meters deep)
and you produce from an ultra-deep well (top of the perforated interval
is at least 20,000 feet TVD SS) or your lease is in waters entirely more
than 200 meters and entirely less than 400 meters deep and you produce
from a deep well (top of the perforated interval is at least 15,000 feet
TVD SS);
(2) Your lease is in the designated area of the GOM (wholly west of
87 degrees, 30 minutes west longitude); and
(3) Your lease is not eligible for deep water royalty relief.

Sec. 203.2 How can I obtain royalty relief?

We may reduce or suspend royalties for Outer Continental Shelf (OCS)
leases or projects that meet the criteria in the following table.

----------------------------------------------------------------------------------------------------------------
Then we may grant you . . .
If you have a lease . . . And if you . . .
----------------------------------------------------------------------------------------------------------------
(a) With earnings that cannot sustain Would abandon otherwise potentially A reduced royalty rate on
production (i.e., End-of-life lease), recoverable resources but seek to current monthly production
increase production by operating beyond and a higher royalty rate
the point at which the lease is on additional monthly
economic under the existing royalty production (see Sec. Sec.
rate, 203.50 through 203.56).

[[Page 11]]

(b) Located in a designated GOM deep Propose an expansion project and can A royalty suspension for a
water area (i.e., 200 meters or greater) demonstrate your project is uneconomic minimum production volume
and acquired in a lease sale held before without royalty relief, plus any additional
November 28, 1995, or after November 28, production large enough to
2000, make the project economic
(see Sec. Sec. 203.60
through 203.79).
(c) Located in a designated GOM deep Are on a field from which no current pre- A royalty suspension for a
water area and acquired in a lease sale Act lease produced (other than test minimum production volume
held before November 28, 1995 (Pre-Act production) before November 28, 1995, plus any additional volume
lease), (Authorized field,) needed to make the field
economic (see Sec. Sec.
203.60 through 203.79).
(d) Located in a designated GOM deep Propose a development project and can A royalty suspension for a
water area and acquired in a lease sale demonstrate that the suspension volume, minimum production volume
held after November 28, 2000, if any, for your lease is not enough to plus any additional volume
make development economic, needed to make your
project economic (see Sec.
Sec. 203.60 through
203.79).
(e) Where royalty relief would recover Are not eligible to apply for end-of- A royalty modification in
significant additional resources or, life or deep water royalty relief, but size, duration, or form
offshore Alaska or in certain areas of show us you meet certain eligibility that makes your lease or
the GOM, would enable development, conditions, project economic (see Sec.
203.80).
(f) Located in a designated GOM shallow Drill a deep well on a lease that is not A royalty suspension for a
water area and acquired in a lease sale eligible for deep water royalty relief volume of gas produced
held before January 1, 2001, or after and you have not previously produced from successful deep and
January 1, 2004, or have exercised an oil or gas from a deep well or an ultra- ultra-deep wells, or, for
option to substitute for royalty relief deep well, certain unsuccessful deep
in your lease terms, and ultra-deep wells, a
smaller royalty suspension
for a volume of gas or oil
produced by all wells on
your lease (see Sec. Sec.
203.40 through 203.49).
(g) Located in a designated GOM shallow Drill and produce gas from an ultra-deep A royalty suspension for a
water area, well on a lease that is not eligible volume of gas produced
for deep water royalty relief and you from successful ultra-deep
have not previously produced oil or gas and deep wells on your
from an ultra-deep well, lease (see Sec. Sec.
203.30 through 203.36).
(h) Located in planning areas offshore Propose an expansion project or propose A royalty suspension for a
Alaska, a development project and can minimum production volume
demonstrate that the project is plus any additional volume
uneconomic without relief or that the needed to make your
suspension volume, if any, for your project economic (see Sec.
lease is not enough to make development Sec. 203.60, 203.62,
economic, 203.67 through 203.70,
203.73, and 203.76 through
203.79).
----------------------------------------------------------------------------------------------------------------

Sec. 203.3 Do I have to pay a fee to request royalty relief?

When you submit an application or ask for a preview assessment, you
must include a fee to reimburse us for our costs of processing your
application or assessment. Federal policy and law require us to recover
the cost of services that confer special benefits to identifiable non-
Federal recipients. The Independent Offices Appropriation Act (31 U.S.C.
9701), Office of Management and Budget Circular A-25, and the Omnibus
Appropriations Bill (Pub. L. 104-134, 110 Stat. 1321, April 26, 1996)
authorize us to collect these fees.
(a) We will specify the necessary fees for each of the types of
royalty relief applications and possible BSEE audits in a Notice to
Lessees. We will periodically update the fees to reflect changes in
costs, as well as provide other information necessary to administer
royalty relief.
(b) You must file all payments electronically through the Fees for
Services page on the BSEE Web site at http://www.bsee.gov, and you must
include a copy of the Pay.gov confirmation receipt page with your
application or assessment.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36148, June 6, 2016]

Sec. 203.4 How do the provisions in this part apply to different types
of leases and projects?

The tables in this section summarize the similar application and
approval provisions for the discretionary end-of-life and deep water
royalty relief programs in Sec. Sec. 203.50 to 203.91. Because royalty
relief for deep gas on leases not subject to deep water royalty relief,
as provided for under Sec. Sec. 203.40 to 203.48, does not involve an
application, its provisions do not parallel the other two royalty relief
programs and are not summarized in this section.

[[Page 12]]

(a) We require the information elements indicated by an X in the
following table and described in Sec. Sec. 203.51, 203.62, and 203.81
through 203.89 for applications for royalty relief.

----------------------------------------------------------------------------------------------------------------
Deep water
End-of-life -----------------------------------------
Information elements lease Expansion Pre-act Development
project lease project
----------------------------------------------------------------------------------------------------------------
(1) Administrative information report................. X X X X
(2) Net revenue and relief justification report X ........... ...........
(prescribed format)..................................
(3) Economic viability and relief justification report .............. X X X
(Royalty Suspension Viability Program (RSVP) model
inputs justified with Geological and Geophysical
(G&G), Engineering, Production, & Cost reports)......
(4) G&G report........................................ .............. X X X
(5) Engineering report................................ .............. X X X
(6) Production report................................. .............. X X X
(7) Deep water cost report............................ .............. X X X
----------------------------------------------------------------------------------------------------------------

(b) We require the confirmation elements indicated by an X in the
following table and described in Sec. Sec. 203.70, 203.81, 203.90 and
203.91 to retain royalty relief.

(c) The following table indicates by an X, and Sec. Sec. 203.50,
203.52, 203.60 and 203.67 describe, the prerequisites for our approval
of your royalty relief application.

----------------------------------------------------------------------------------------------------------------
Deep water
End-of-life -----------------------------------------
Approval conditions lease Pre-act Development
Expansion lease project
----------------------------------------------------------------------------------------------------------------
(1) At least 12 of the last 15 months have the X
required level of production.........................
(2) Already producing................................. X ...........
(3) A producible well into a reservoir that has not .............. X X X
produced before......................................
(4) Royalties for qualifying months exceed 75 percent X ........... ...........
of net revenue (NR)..................................
(5) Substantial investment on a pre-Act lease (e.g., .............. ........... ...........
platform, subsea template)...........................
(6) Determined to be economic only with relief........ .............. X X X
----------------------------------------------------------------------------------------------------------------

(d) The following table indicates by an X, and Sec. Sec. 203.52,
203.74, and 203.75 describe, the prerequisites for a redetermination of
our royalty relief decision.

[[Page 13]]

(e) The following table indicates by an X, and Sec. Sec. 203.53 and
203.69 describe, the characteristics of approved royalty relief.

----------------------------------------------------------------------------------------------------------------
Deep water
End-of-life -----------------------------------------
Relief rate and volume, subject to certain conditions lease Expansion Pre-act Development
project lease project
----------------------------------------------------------------------------------------------------------------
(1) One-half pre-application effective lease rate on X ........... ...........
the qualifying amount, 1.5 times pre-application
effective lease rate on additional production up to
twice the qualifying amount, and the pre-application
effective lease rate for any larger volumes..........
(2) Qualifying amount is the average monthly X ........... ...........
production for 12 qualifying months..................
(3) Zero royalty rate on the suspension volume and the .............. X X X
original lease rate on additional production.........
(4) Suspension volume is at least 17.5, 52.5 or 87.5 .............. ........... X
million barrels of oil equivalent (MMBOE)............
(5) Suspension volume is at least the minimum set in .............. X ........... X
the Notice of Sale, the lease, or the regulations....
(6) Amount needed to become economic.................. .............. X X X
----------------------------------------------------------------------------------------------------------------

(f) The following table indicates by an X, and Sec. Sec. 203.54 and
203.78 describe, circumstances under which we discontinue your royalty
relief.

----------------------------------------------------------------------------------------------------------------
Deep water
End-of-life -----------------------------------------
Full royalty resumes when lease Expansion Pre-act Development
project lease project
----------------------------------------------------------------------------------------------------------------
(1) Average NYMEX price for last 12 months is at least X ........... ...........
25 percent above the average for the qualifying
months...............................................
(2) Average NYMEX price for last calendar year exceeds .............. X X
$28/bbl or $3.50/mcf, escalated by the gross domestic
product (GDP) deflator since 1994....................
(3) Average prices for designated periods exceed .............. X ........... X
levels we specify in the Notice of Sale or the lease.
----------------------------------------------------------------------------------------------------------------

(g) The following table indicates by an X, and Sec. Sec. 203.55,
203.76, and 203.77 describe, circumstances under which we end or reduce
royalty relief.

----------------------------------------------------------------------------------------------------------------
Deep water
End-of-life -----------------------------------------
Relief withdrawn or reduced lease Expansion Pre-act Development
project lease project
----------------------------------------------------------------------------------------------------------------
(1) If recipient requests............................. X X X X
(2) Lease royalty rate is at the effective rate for 12 X ........... ...........
consecutive months...................................
(3) Conditions occur that we specified in the approval X ........... ...........
letter in individual cases...........................
(4) Recipient does not submit post-production report .............. X X X
that compares expected to actual costs...............
(5) Recipient changes development system.............. .............. X X X
(6) Recipient excessively delays starting fabrication. .............. X X X
(7) Recipient spends less than 80 percent of proposed .............. X X X
pre-production costs prior to start of production....
(8) Amount of relief volume is produced............... .............. X X X
----------------------------------------------------------------------------------------------------------------

Sec. 203.5 What is BSEE's authority to collect information?

(a) The Office of Management and Budget (OMB) has approved the
information collection requirements in this part under 44 U.S.C. 3501 et
seq., and assigned OMB Control Number 1014-0005. The title of this
information collection is ``30 CFR part 203, Relief or Reduction in
Royalty Rates.''
(b) BSEE collects this information to make decisions on the economic
viability of leases requesting a suspension or elimination of royalty or
net profit share. Responses are required to obtain

[[Page 14]]

a benefit or are mandatory according to 43 U.S.C. 1331 et seq. BSEE will
protect information considered proprietary under applicable law and
under regulations at Sec. 203.61, ``How do I assess my chances for
getting relief?'' and 30 CFR 250.197, ``Data and information to be made
available to the public or for limited inspection.''
(c) An agency may not conduct or sponsor, and a person is not
required to respond to a collection of information unless it displays a
currently valid OMB control number.
(d) Send comments regarding any aspect of the collection of
information under this part, including suggestions for reducing the
burden, to the Information Collection Clearance Officer, Bureau of
Safety and Environmental Enforcement, 45600 Woodland Road, Sterling, VA
20166.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36148, June 6, 2016]

Subpart B_OCS Oil, Gas, and Sulfur General

Royalty Relief for Drilling Ultra-Deep Wells on Leases Not Subject to
Deep Water Royalty Relief

Sec. 203.30 Which leases are eligible for royalty relief as a result
of drilling a phase 2 or phase 3 ultra-deep well?

Your lease may receive a royalty suspension volume (RSV) under
Sec. Sec. 203.31 through 203.36 if the lease meets all the requirements
of this section.
(a) The lease is located in the GOM wholly west of 87 degrees, 30
minutes West longitude in water depths entirely less than 400 meters
deep.
(b) The lease has not produced gas or oil from a deep well or an
ultra-deep well, except as provided in Sec. 203.31(b).
(c) If the lease is located entirely in more than 200 meters and
entirely less than 400 meters of water, it must either:
(1) Have been issued before November 28, 1995, and not been granted
deep water royalty relief under 43 U.S.C. 1337(a)(3)(C), added by
section 302 of the Deep Water Royalty Relief Act; or
(2) Have been issued after November 28, 2000, and not been granted
deep water royalty relief under Sec. Sec. 203.60 through 203.79.

Sec. 203.31 If I have a qualified phase 2 or qualified phase 3
ultra-deep well, what royalty relief would that well earn for my lease?

(a) Subject to the administrative requirements of Sec. 203.35 and
the price conditions in Sec. 203.36, your qualified well earns your
lease an RSV shown in the following table in billions of cubic feet
(BCF) or in thousands of cubic feet (MCF) as prescribed in Sec. 203.33:

------------------------------------------------------------------------
If you have a qualified phase 2 or Then your lease earns an RSV on
qualified phase 3 ultra-deep well that this volume of gas production:
is:
------------------------------------------------------------------------
(1) An original well, 35 BCF.
(2) A sidetrack with a sidetrack 35 BCF.
measured depth of at least 20,000
feet,
(3) An ultra-deep short sidetrack that 4 BCF plus 600 MCF times
is a phase 2 ultra-deep well, sidetrack measured depth
(rounded to the nearest 100
feet) but no more than 25 BCF.
(4) An ultra-deep short sidetrack that 0 BCF.
is a phase 3 ultra-deep well,
------------------------------------------------------------------------

(b)(1) This paragraph applies if your lease:
(i) Has produced gas or oil from a deep well with a perforated
interval the top of which is less than 18,000 feet TVD SS;
(ii) Was issued in a lease sale held between January 1, 2004, and
December 31, 2005; and
(iii) The terms of your lease expressly incorporate the provisions
of Sec. Sec. 203.41 through 203.47 as they existed at the time the
lease was issued.
(2) Subject to the administrative requirements of Sec. 203.35 and
the price conditions in Sec. 203.36, your qualified well earns your
lease an RSV shown in the

[[Page 15]]

following table in BCF or MCF as prescribed in Sec. 203.33:

------------------------------------------------------------------------
Then your lease earns an RSV on
If you have a qualified phase 2 ultra- this volume of gas production:
deep well that is . . .
------------------------------------------------------------------------
(i) An original well or a sidetrack 10 BCF.
with a sidetrack measured depth of at
least 20,000 feet TVD SS,
(ii) An ultra-deep short sidetrack, 4 BCF plus 600 MCF times
sidetrack measured depth
(rounded to the nearest 100
feet) but no more than 10 BCF.
------------------------------------------------------------------------

(c) Lessees may request a refund of or recoup royalties paid on
production from qualified phase 2 or phase 3 ultra-deep wells that:
(1) Occurs before December 18, 2008, and
(2) Is subject to application of an RSV under either Sec. 203.31 or
Sec. 203.41.
(d) The following examples illustrate how this section applies.
These examples assume that your lease is located in the GOM west of 87
degrees, 30 minutes West longitude and in water less than 400 meters
deep (see Sec. 203.30(a)), has no existing deep or ultra-deep wells and
that the price thresholds prescribed in Sec. 203.36 have not been
exceeded.

Example 1: In 2008, you drill and begin producing from an ultra-deep
well with a perforated interval the top of which is 25,000 feet TVD SS,
and your lease has had no prior production from a deep or ultra-deep
well. Assuming your lease has no deepwater royalty relief (see Sec.
203.30(c)), your lease is eligible (according to Sec. 203.30(b)) to
earn an RSV under Sec. 203.31 because it has not yet produced from a
deep well. Your lease earns an RSV of 35 BCF under this section when
this well begins producing. According to Sec. 203.31(a), your 25,000
foot well qualifies your lease for this RSV because the well was drilled
after the relief authorized here became effective (when the proposed
version of this rule was published on May 18, 2007) and produced from an
interval that meets the criteria for an ultra-deep well (i.e., is a
phase 2 ultra-deep well as defined in Sec. 203.0). Then in 2014, you
drill and produce from another ultra-deep well with a perforated
interval the top of which is 29,000 feet TVD SS. Your lease earns no
additional RSV under this section when this second ultra-deep well
produces, because your lease no longer meets the condition in (Sec.
203.30(b)) of no production from a deep well. However, any remaining RSV
earned by the first ultra-deep well on your lease would be applied to
production from both the first and the second ultra-deep wells as
prescribed in Sec. 203.33(a)(2), or Sec. 203.33(b)(2) if your lease is
part of a unit.
Example 2: In 2005, you spudded and began producing from an ultra-
deep well with a perforated interval the top of which is 23,000 feet TVD
SS. Your lease earns no RSV under this section from this phase 1 ultra-
deep well (as defined in Sec. 203.0) because you spudded the well
before the publication date (May 18, 2007) of the proposed rule when
royalty relief under Sec. 203.31(a) became effective. However, this
ultra-deep well may earn an RSV of 25 BCF for your lease under Sec.
203.41 (that became effective May 3, 2004), if the lease is located in
water depths partly or entirely less than 200 meters and has not
previously produced from a deep well (Sec. 203.30(b)).
Example 3: In 2000, you began producing from a deep well with a
perforated interval the top of which is 16,000 feet TVD SS and your
lease is located in water 100 meters deep. Then in 2008, you drill and
produce from a new ultra-deep well with a perforated interval the top of
which is 24,000 feet TVD SS. Your lease earns no RSV under either this
section or Sec. 203.41 because the 16,000-foot well was drilled before
we offered any way to earn an RSV for producing from a deep well (see
dates in the definition of qualified well in Sec. 203.0) and because
the existence of the 16,000-foot well means the lease is not eligible
(see Sec. 203.30(b)) to earn an RSV for the 24,000-foot well. Because
the lease existed in the year 2000, it cannot be eligible for the
exception to this eligibility condition provided in Sec. 203.31(b).
Example 4: In 2008, you spud and produce from an ultra-deep well
with a perforated interval the top of which is 22,000 feet TVD SS, your
lease is located in water 300 meters deep, and your lease has had no
previous production from a deep or ultra-deep well. Your lease earns an
RSV of 35 BCF under this section when this well begins producing because
your lease meets the conditions in Sec. 203.30 and the well fits the
definition of a phase 2 ultra-deep well (in Sec. 203.0). Then in 2010,
you spud and produce from a deep well with a perforated interval the top
of which is 16,000 feet TVD SS. Your 16,000-foot well earns no RSV
because it is on a lease that already has a producing well at least
18,000 feet subsea (see Sec. 203.42(a)), but any remaining RSV earned
by the ultra-deep well would also be applied to production from the deep
well as prescribed in Sec. 203.33(a)(2), or Sec. 203.33(b)(2) if your
lease is part of a unit and Sec. 203.43(a)(2),

[[Page 16]]

or Sec. 203.43(b)(2) if your lease is part of a unit. However, if the
16,000-foot deep well does not begin production until 2016 (or if your
lease were located in water less than 200 meters deep), then the 16,000-
foot well would not be a qualified deep well because this well does not
begin production within the interval specified in the definition of a
qualified well in Sec. 203.0, and the RSV earned by the ultra-deep well
would not be applied to production from this (unqualified) deep well.
Example 5: In 2008, you spud a deep well with a perforated interval
the top of which is 17,000 feet TVD SS that becomes a qualified well and
earns an RSV of 15 BCF under Sec. 203.41 when it begins producing. Then
in 2011, you spud an ultra-deep well with a perforated interval the top
of which is 26,000 feet TVD SS. Your 26,000-foot well becomes a
qualified ultra-deep well because it meets the date and depth conditions
in this definition under Sec. 203.0 when it begins producing, but your
lease earns no additional RSV under this section or Sec. 203.41 because
it is on a lease that already has production from a deep well (see Sec.
203.30(b)). Both the qualified deep well and the qualified ultra-deep
well would share your lease's total RSV of 15 BCF in the manner
prescribed in Sec. Sec. 203.33 and 203.43.
Example 6: In 2008, you spud a qualified ultra-deep well that is a
sidetrack with a sidetrack measured depth of 21,000 feet and a
perforated interval the top of which is 25,000 feet TVD SS. This well
meets the definition of an ultra-deep well but is too long to be
classified an ultra-deep short sidetrack in Sec. 203.0. If your lease
is located in 150 meters of water and has not previously produced from a
deep well, your lease earns an RSV of 35 BCF because it was drilled
after the effective date for earning this RSV. Further, this RSV applies
to gas production from this and any future qualified deep and qualified
ultra-deep wells on your lease, as prescribed in Sec. 203.33. The
absence of an expiration date for earning an RSV on an ultra-deep well
means this long sidetrack well becomes a qualified well whenever it
starts production. If your sidetrack has a sidetrack measured depth of
14,000 feet and begins production in March 2009, it earns an RSV of 12.4
BCF under this section because it meets the definitions of a phase 2
ultra-deep well (production begins before the expiration date for the
pre-existing relief in its water depth category) and an ultra-deep short
sidetrack in Sec. 203.0. However, if it does not begin production until
2010, it earns no RSV because it is too short as a phase 3 ultra-deep
well to be a qualified ultra-deep well.
Example 7: Your lease was issued in June 2004 and expressly
incorporates the provisions of Sec. Sec. 203.41 through 203.47 as they
existed at that time. In January 2005, you spud a deep well (well no. 1)
with a perforated interval the top of which is 16,800 feet TVD SS that
becomes a qualified well and earns an RSV of 15 BCF under Sec. 203.41
when it begins producing. Then in February 2008, you spud an ultra-deep
well (well no. 2) with a perforated interval the top of which is 22,300
feet that begins producing in November 2008, after well no. 1 has
started production. Well no. 2 earns your lease an additional RSV of 10
BCF under paragraph (b) of this section because it begins production in
time to be classified as a phase 2 ultra-deep well. If, on the other
hand, well no. 2 had begun producing in June 2009, it would earn no
additional RSV for the lease because it would be classified as a phase 3
ultra-deep well and thus is not entitled to the exception under
paragraph (b) of this section.

Sec. 203.32 What other requirements or restrictions apply to royalty relief
for a qualified phase 2 or phase 3 ultra-deep well?

(a) If a qualified ultra-deep well on your lease is within a
unitized portion of your lease, the RSV earned by that well under this
section applies only to your lease and not to other leases within the
unit or to the unit as a whole.
(b) If your qualified ultra-deep well is a directional well (either
an original well or a sidetrack) drilled across a lease line, then
either:
(1) The lease with the perforated interval that initially produces
earns the RSV or
(2) If the perforated interval crosses a lease line, the lease where
the surface of the well is located earns the RSV.
(c) Any RSV earned under Sec. 203.31 is in addition to any royalty
suspension supplement (RSS) for your lease under Sec. 203.45 that
results from a different wellbore.
(d) If your lease earns an RSV under Sec. 203.31 and later produces
from a deep well that is not a qualified well, the RSV is not forfeited
or terminated, but you may not apply the RSV earned under Sec. 203.31
to production from the non-qualified well.
(e) You owe minimum royalties or rentals in accordance with your
lease terms notwithstanding any RSVs allowed under paragraphs (a) and
(b) of Sec. 203.31.
(f) Unused RSVs transfer to a successor lessee and expire with the
lease.

[[Page 17]]

Sec. 203.33 To which production do I apply the RSV earned by qualified
phase 2 and phase 3 ultra-deep wells on my lease or in my unit?

(a) You must apply the RSV allowed in Sec. 203.31(a) and (b) to gas
volumes produced from qualified wells on or after May 18, 2007, reported
on the Oil and Gas Operations Report, Part A (OGOR-A) for your lease
under 30 CFR 1210.102. All gas production from qualified wells reported
on the OGOR-A, including production not subject to royalty, counts
toward the total lease RSV earned by both deep or ultra-deep wells on
the lease.
(b) This paragraph applies to any lease with a qualified phase 2 or
phase 3 ultra-deep well that is not within a BSEE-approved unit. Subject
to the price conditions of Sec. 203.36, you must apply the RSV
prescribed in Sec. 203.31 as required under the following paragraphs
(b)(1) and (b)(2) of this section.
(1) You must apply the RSV to the earliest gas production occurring
on and after the later of May 18, 2007, or the date the first qualified
phase 2 or phase 3 ultra-deep well that earns your lease the RSV begins
production (other than test production).
(2) You must apply the RSV to only gas production from qualified
wells on your lease, regardless of their depth, for which you have met
the requirements in Sec. 203.35 or Sec. 203.44.
(c) This paragraph applies to any lease with a qualified phase 2 or
phase 3 ultra-deep well where all or part of the lease is within a BSEE-
approved unit. Under the unit agreement, a share of the production from
all the qualified wells in the unit participating area would be
allocated to your lease each month according to the participating area
percentages. Subject to the price conditions of Sec. 203.36, you must
apply the RSV prescribed in Sec. 203.31 as follows:
(1) You must apply the RSV to the earliest gas production occurring
on and after the later of May 18, 2007, or the date that the first
qualified phase 2 or phase 3 ultra-deep well that earns your lease the
RSV begins production (other than test production).
(2) You must apply the RSV to only gas production:
(i) From qualified wells on the non-unitized area of your lease,
regardless of their depth, for which you have met the requirements in
Sec. 203.35 or Sec. 203.44; and
(ii) Allocated to your lease under a BSEE-approved unit agreement
from qualified wells on unitized areas of your lease and on other leases
in participating areas of the unit, regardless of their depth, for which
the requirements in Sec. 203.35 or Sec. 203.44 have been met. The
allocated share under paragraph (a)(2)(ii) of this section does not
increase the RSV for your lease.

Example: The east half of your lease A is unitized with all of lease
B. There is one qualified phase 2 ultra-deep well on the non-unitized
portion of lease A that earns lease A an RSV of 35 BCF under Sec.
203.31, one qualified deep well on the unitized portion of lease A
(drilled after the ultra-deep well on the non-unitized portion of that
lease) and a qualified phase 2 ultra-deep well on lease B that earns
lease B a 35 BCF RSV under Sec. 203.31. The participating area
percentages allocate 40 percent of production from both of the unit
qualified wells to lease A and 60 percent to lease B. If the non-
unitized qualified phase 2 ultra-deep well on lease A produces 12 BCF,
and the unitized qualified well on lease A produces 18 BCF, and the
qualified well on lease B produces 37 BCF, then the production volume
from and allocated to lease A to which the lease A RSV applies is 34 BCF
[12 + (18 + 37)(0.40)]. The production volume allocated to lease B to
which the lease B RSV applies is 33 BCF [(18 + 37)(0.60)]. None of the
volumes produced from a well that is not within a unit participating
area may be allocated to other leases in the unit.

(d) You must begin paying royalties when the cumulative production
of gas from all qualified wells on your lease, or allocated to your
lease under paragraph (b) of this section, reaches the applicable RSV
allowed under Sec. 203.31 or Sec. 203.41. For the month in which
cumulative production reaches this RSV, you owe royalties on the portion
of gas production from or allocated to your lease that exceeds the RSV
remaining at the beginning of that month.

Sec. 203.34 To which production may an RSV earned by qualified
phase 2 and phase 3 ultra-deep wells on my lease not be applied?

You may not apply an RSV earned under Sec. 203.31:

[[Page 18]]

(a) To production from completions less than 15,000 feet TVD SS,
except in cases where the qualified well is re-perforated in the same
reservoir previously perforated deeper than 15,000 feet TVD SS;
(b) To production from a deep well or ultra-deep well on any other
lease, except as provided in paragraph (c) of Sec. 203.33;
(c) To any liquid hydrocarbon (oil and condensate) volumes; or
(d) To production from a deep well or ultra-deep well that commenced
drilling before:
(1) March 26, 2003, on a lease that is located entirely or partly in
water less than 200 meters deep; or
(2) May 18, 2007, on a lease that is located entirely in water more
than 200 meters deep.

Sec. 203.35 What administrative steps must I take to use the RSV earned
by a qualified phase 2 or phase 3 ultra-deep well?

To use an RSV earned under Sec. 203.31:
(a) You must notify the BSEE Regional Supervisor for Production and
Development in writing of your intent to begin drilling operations on
all your ultra-deep wells.
(b) Before beginning production, you must meet any production
measurement requirements that the BSEE Regional Supervisor for
Production and Development has determined are necessary under 30 CFR
part 250, subpart L.
(c)(1) Within 30 days of the beginning of production from any wells
that would become qualified phase 2 or phase 3 ultra-deep wells by
satisfying the requirements of this section:
(i) Provide written notification to the BSEE Regional Supervisor for
Production and Development that production has begun; and
(ii) Request confirmation of the size of the RSV earned by your
lease.
(2) If you produced from a qualified phase 2 or phase 3 ultra-deep
well before December 18, 2008, you must provide the information in
paragraph (c)(1) of this section no later than January 20, 2009.
(d) If you cannot produce from a well that otherwise meets the
criteria for a qualified phase 2 ultra-deep well that is an ultra-deep
short sidetrack before May 3, 2009, on a lease that is located entirely
or partly in water less than 200 meters deep, or before May 3, 2013, on
a lease that is located entirely in water more than 200 meters but less
than 400 meters deep, the BSEE Regional Supervisor for Production and
Development may extend the deadline for beginning production for up to 1
year, based on the circumstances of the particular well involved, if it
meets all the following criteria.
(1) The delay occurred after drilling reached the total depth in
your well.
(2) Production (other than test production) was expected to begin
from the well before May 3, 2009, on a lease that is located entirely or
partly in water less than 200 meters deep or before May 3, 2013, on a
lease that is located entirely in water more than 200 meters but less
than 400 meters deep. You must provide a credible activity schedule with
supporting documentation.
(3) The delay in beginning production is for reasons beyond your
control, such as adverse weather and accidents which BSEE deems were
unavoidable.

Sec. 203.36 Do I keep royalty relief if prices rise significantly?

(a) You must pay the Office of Natural Resources Revenue royalties
on all gas production to which an RSV otherwise would be applied under
Sec. 203.33 for any calendar year in which the average daily closing
New York Mercantile Exchange (NYMEX) natural gas price exceeds the
applicable threshold price shown in the following table.

------------------------------------------------------------------------
A price threshold in year 2007 dollars
of . . . Applies to . . .
------------------------------------------------------------------------
(1) $10.15 per MMBtu, (i) The first 25 BCF of RSV
earned under Sec. 203.31(a)
by a phase 2 ultra-deep well
on a lease that is located in
water partly or entirely less
than 200 meters deep issued
before December 18, 2008; and
(ii) Any RSV earned under Sec.
203.31(b) by a phase 2 ultra-
deep well.

[[Page 19]]

(2) $4.55 per MMBtu, (i) Any RSV earned under Sec.
203.31(a) by a phase 3 ultra-
deep well unless the lease
terms prescribe a different
price threshold;
(ii) The last 10 BCF of the 35
BCF of RSV earned under Sec.
203.31(a) by a phase 2 ultra-
deep well on a lease that is
located in water partly or
entirely less than 200 meters
deep issued before December
18, 2008, and that is not a
non-converted lease;
(iii) The last 15 BCF of the 35
BCF of RSV earned under Sec.
203.31(a) by a phase 2 ultra-
deep well on a non-converted
lease;
(iv) Any RSV earned under Sec.
203.31(a) by a phase 2 ultra-
deep well on a lease in water
partly or entirely less than
200 meters deep issued on or
after December 18, 2008,
unless the lease terms
prescribe a different price
threshold; and
(v) Any RSV earned under Sec.
203.31(a) by a phase 2 ultra-
deep well on a lease in water
entirely more than 200 meters
deep and entirely less than
400 meters deep.
(3) $4.08 per MMBtu, (i) The first 20 BCF of RSV
earned by a well that is
located on a non-converted
lease issued in OCS Lease Sale
178.
(4) $5.83 per MMBtu, (i) The first 20 BCF of RSV
earned by a well that is
located on a non-converted
lease issued in OCS Lease
Sales 180, 182, 184, 185, or
187.
------------------------------------------------------------------------

(b) For purposes of paragraph (a) of this section, determine the
threshold price for any calendar year after 2007 by:
(1) Determining the percentage of change during the year in the
Department of Commerce's implicit price deflator for the gross domestic
product; and
(2) Adjusting the threshold price for the previous year by that
percentage.
(c) The following examples illustrate how this section applies.

Example 1: Assume that a lessee drills and begins producing from a
qualified phase 2 ultra-deep well in 2008 on a lease issued in 2004 in
less than 200 meters of water that earns the lease an RSV of 35 BCF.
Further, assume the well produces a total of 18 BCF by the end of 2009
and in both of those years, the average daily NYMEX closing natural gas
price is less than $10.15 (adjusted for inflation after 2007). The
lessee does not pay royalty on the 18 BCF because the gas price
threshold under paragraph (a)(1) of this section applies to the first 25
BCF of this RSV earned by this phase 2 ultra-deep well. In 2010, the
well produces another 13 BCF. In that year, the average daily closing
NYMEX natural gas price is greater than $4.55 per MMBtu (adjusted for
inflation after 2007), but less than $10.15 per MMBtu (adjusted for
inflation after 2007). The first 7 BCF produced in 2010 will exhaust the
first 25 BCF (that is subject to the $10.15 threshold) of the 35 BCF RSV
that the well earned. The lessee must pay royalty on the remaining 6 BCF
produced in 2010, because it is subject to the $4.55 per MMBtu threshold
under paragraph (a)(2)(ii) of this section which was exceeded.
Example 2: Assume that a lessee:
(1) Drills and produces from well no.1, a qualified deep well in
2008 to a depth of 15,500 feet TVD SS that earns a 15 BCF RSV for the
lease under Sec. 203.41, which would be subject to a price threshold of
$10.15 per MMBtu (adjusted for inflation after 2007), meaning the lease
is partly or entirely in less than 200 meters of water;
(2) Later in 2008, drills and produces from well no. 2, a second
qualified deep well to a depth of 17,000 feet TVD SS that earns no
additional RSV (see Sec. 203.41(c)(1)); and
(3) In 2015, drills and produces from well no. 3, a qualified phase
3 ultra-deep well that earns no additional RSV since the lease already
has an RSV established by prior deep well production. Further assume
that in 2015, the average daily closing NYMEX natural gas price exceeds
$4.55 per MMBtu (adjusted for inflation after 2007) but does not exceed
$10.15 per MMBtu (adjusted for inflation after 2007). In 2015, any
remaining RSV earned by well no. 1 (which would have been applied to
production from well nos. 1 and 2 in the intervening years), would be
applied to production from all three qualified wells. Because the price
threshold applicable to that RSV was not exceeded, the production from
all three qualified wells would be royalty-free until the 15 BCF RSV
earned by well no. 1 is exhausted.
Example 3: Assume the same initial facts regarding the three wells
as in Example 2. Further assume that well no. 1 stopped producing in
2011 after it had produced 8 BCF, and that well no. 2 stopped producing
in 2012 after it had produced 5 BCF. Two BCF of the RSV earned by well
no. 1 remain. That RSV would be applied to production from well no.

[[Page 20]]

3 until it is exhausted, and the lessee therefore would not pay royalty
on those 2 BCF produced in 2015, because the $10.15 per MMBtu (adjusted
for inflation after 2007) price threshold is not exceeded. The
determination of which price threshold applies to deep gas production
depends on when the first qualified well earned the RSV for the lease,
not on which wells use the RSV.
Example 4: Assume that in February 2010, a lessee completes and
begins producing from an ultra-deep well (at a depth of 21,500 feet TVD
SS) on a lease located in 325 meters of water with no prior production
from any deep well and no deep water royalty relief. The ultra-deep well
would be a phase 2 ultra-deep well (see definition in Sec. 203.0), and
would earn the lease an RSV of 35 BCF under Sec. Sec. 203.30 and
203.31. Further assume that the average daily closing NYMEX natural gas
price exceeds $4.55 per MMBtu (adjusted for inflation after 2007) but
does not exceed $10.15 per MMBtu (adjusted for inflation after 2007)
during 2010. Because the lease is located in more than 200 but less than
400 meters of water, the $4.55 per MMBtu price threshold applies to the
whole RSV (see paragraph (a)(2)(v) of this section), and the lessee will
owe royalty on all gas produced from the ultra-deep well in 2010.

(d) You must pay any royalty due under this section no later than
March 31 of the year following the calendar year for which you owe
royalty. If you do not pay by that date, you must pay late payment
interest under 30 CFR 1218.54 from April 1 until the date of payment.
(e) Production volumes on which you must pay royalty under this
section count as part of your RSV.

Royalty Relief for Drilling Deep Gas Wells on Leases Not Subject to Deep
Water Royalty Relief

Sec. 203.40 Which leases are eligible for royalty relief as a result
of drilling a deep well or a phase 1 ultra-deep well?

Your lease may receive an RSV under Sec. Sec. 203.41 through
203.44, and may receive an RSS under Sec. Sec. 203.45 through 203.47,
if it meets all the requirements of this section.
(a) The lease is located in the GOM wholly west of 87 degrees, 30
minutes West longitude in water depths entirely less than 400 meters
deep.
(b) The lease has not produced gas or oil from a well with a
perforated interval the top of which is 18,000 feet TVD SS or deeper
that commenced drilling either:
(1) Before March 26, 2003, on a lease that is located partly or
entirely in water less than 200 meters deep; or
(2) Before May 18, 2007, on a lease that is located in water
entirely more than 200 meters and entirely less than 400 meters deep.
(c) In the case of a lease located partly or entirely in water less
than 200 meters deep, the lease was issued in a lease sale held either:
(1) Before January 1, 2001;
(2) On or after January 1, 2001, and before January 1, 2004, and, in
cases where the original lease terms provided for an RSV for deep gas
production, the lessee has exercised the option provided for in Sec.
203.49; or
(3) On or after January 1, 2004, and the lease terms provide for
royalty relief under Sec. Sec. 203.41 through 203.47. (Note: Because
the original Sec. 203.41 has been divided into new Sec. Sec. 203.41
and 203.42 and subsequent sections have been redesignated as Sec. Sec.
203.43 through 203.48, royalty relief in lease terms for leases issued
on or after January 1, 2004, should be read as referring to Sec. Sec.
203.41 through 203.48.)
(d) If the lease is located entirely in more than 200 meters and
less than 400 meters of water, it must either:
(1) Have been issued before November 28, 1995, and not been granted
deep water royalty relief under 43 U.S.C. 1337(a)(3)(C), added by
section 302 of the Deep Water Royalty Relief Act; or
(2) Have been issued after November 28, 2000, and not been granted
deep water royalty relief under Sec. Sec. 203.60 through 203.79.

Sec. 203.41 If I have a qualified deep well or a qualified phase 1
ultra-deep well, what royalty relief would my lease earn?

(a) To qualify for a suspension volume under paragraphs (b) or (c)
of this section, your lease must meet the requirements in Sec. 203.40
and the requirements in the following table.

[[Page 21]]

------------------------------------------------------------------------
And if it later . . Then your lease . .
If your lease has not . . . . .
------------------------------------------------------------------------
(1) produced gas or oil from Has a qualified deep earns an RSV
any deep well or ultra-deep well or qualified specified in
well, phase 1 ultra-deep paragraph (b) of
well, this section.
(2) produced gas or oil from Has a qualified deep earns an RSV
a well with a perforated well with a specified in
interval whose top is perforated interval paragraph (c) of
18,000 feet TVD SS or whose top is 18,000 this section.
deeper, feet TVD SS or
deeper or a
qualified phase 1
ultra-deep well,
------------------------------------------------------------------------

(b) If your lease meets the requirements in paragraph (a)(1) of this
section, it earns the RSV prescribed in the following table:

------------------------------------------------------------------------
If you have a qualified deep well or a Then your lease earns an RSV on
qualified phase 1 ultra-deep well that this volume of gas production:
is:
------------------------------------------------------------------------
(1) An original well with a perforated 15 BCF.
interval the top of which is from
15,000 to less than 18,000 feet TVD
SS,
(2) A sidetrack with a perforated 4 BCF plus 600 MCF times
interval the top of which is from sidetrack measured depth
15,000 to less than 18,000 feet TVD (rounded to the nearest 100
SS, feet) but no more than 15 BCF.
(3) An original well with a perforated 25 BCF.
interval the top of which is at least
18,000 feet TVD SS,
(4) A sidetrack with a perforated 4 BCF plus 600 MCF times
interval the top of which is at least sidetrack measured depth
18,000 feet TVD SS, (rounded to the nearest 100
feet) but no more than 25 BCF.
------------------------------------------------------------------------

(c) If your lease meets the requirements in paragraph (a)(2) of this
section, it earns the RSV prescribed in the following table. The RSV
specified in this paragraph is in addition to any RSV your lease already
may have earned from a qualified deep well with a perforated interval
whose top is from 15,000 feet to less than 18,000 feet TVD SS.

------------------------------------------------------------------------
If you have a qualified deep well or a
qualified phase 1 ultra-deep well that Then you earn an RSV on this
is . . . amount of gas production:
------------------------------------------------------------------------
(1) An original well or a sidetrack 0 BCF.
with a perforated interval the top of
which is from 15,000 to less than
18,000 feet TVD SS,
(2) An original well with a perforated 10 BCF.
interval the top of which is 18,000
feet TVD SS or deeper,
(3) A sidetrack with a perforated 4 BCF plus 600 MCF times
interval the top of which is 18,000 sidetrack measured depth
feet TVD SS or deeper, (rounded to the nearest 100
feet) but no more than 10 BCF.
------------------------------------------------------------------------

(d) Lessees may request a refund of or recoup royalties paid on
production from qualified wells on a lease that is located in water
entirely deeper than 200 meters but entirely less than 400 meters deep
that:
(1) Occurs before December 18, 2008; and
(2) Is subject to application of an RSV under either Sec. 203.31 or
Sec. 203.41.
(e) The following examples illustrate how this section applies,
assuming your lease meets the location, prior production, and lease
issuance conditions in Sec. 203.40 and paragraph (a) of this section:

Example 1: If you have a qualified deep well that is an original
well with a perforated interval the top of which is 16,000 feet TVD SS,
your lease earns an RSV of 15 BCF under paragraph (b)(1) of this
section. This RSV must be applied to gas production from all qualified
wells on your lease, as prescribed in Sec. Sec. 203.43 and 203.48.
However, if the top of the perforated interval is 18,500 feet TVD SS,
the RSV is 25 BCF according to paragraph (b)(3) of this section.
Example 2: If you have a qualified deep well that is a sidetrack,
with a perforated interval the top of which is 16,000 feet TVD SS and a
sidetrack measured depth of 6,789 feet, we round the measured depth to
6,800 feet and your lease earns an RSV of 8.08 BCF under paragraph
(b)(2) of this section. This RSV would be applied to gas production from
all qualified wells on your lease, as prescribed in Sec. Sec. 203.43
and 203.48.
Example 3: If you have a qualified deep well that is a sidetrack,
with a perforated interval the top of which is 16,000 feet TVD SS and a
sidetrack measured depth of 19,500 feet, your lease earns an RSV of 15
BCF. This RSV would be applied to gas production from all qualified
wells on your lease, as prescribed in Sec. Sec. 203.43 and 203.48, even
though 4 BCF plus 600 MCF per foot of sidetrack measured

[[Page 22]]

depth equals 15.7 BCF because paragraph (b)(2) of this section limits
the RSV for a sidetrack at the amount an original well to the same depth
would earn.
Example 4: If you have drilled and produced a deep well with a
perforated interval the top of which is 16,000 feet TVD SS before March
26, 2003 (and the well therefore is not a qualified well and has earned
no RSV under this section), and later drill:
(i) A deep well with a perforated interval the top of which is
17,000 feet TVD SS, your lease earns no RSV (see paragraph (c)(1) of
this section);
(ii) A qualified deep well that is an original well with a
perforated interval the top of which is 19,000 feet TVD SS, your lease
earns an RSV of 10 BCF under paragraph (c)(2) of this section. This RSV
would be applied to gas production from qualified wells on your lease,
as prescribed in Sec. Sec. 203.43 and 203.48; or
(iii) A qualified deep well that is a sidetrack with a perforated
interval the top of which is 19,000 feet TVD SS, that has a sidetrack
measured depth of 7,000 feet, your lease earns an RSV of 8.2 BCF under
paragraph (c)(3) of this section. This RSV would be applied to gas
production from qualified wells on your lease, as prescribed in
Sec. Sec. 203.43 and 203.48.
Example 5: If you have a qualified deep well that is an original
well with a perforated interval the top of which is 16,000 feet TVD SS,
and later drill a second qualified well that is an original well with a
perforated interval the top of which is 19,000 feet TVD SS, we increase
the total RSV for your lease from 15 BCF to 25 BCF under paragraph
(c)(2) of this section. We will apply that RSV to gas production from
all qualified wells on your lease, as prescribed in Sec. Sec. 203.43
and 203.48. If the second well has a perforated interval the top of
which is 22,000 feet TVD SS (instead of 19,000 feet), the total RSV for
your lease would increase to 25 BCF only in 2 situations: (1) If the
second well was a phase 1 ultra-deep well, i.e., if drilling began
before May 18, 2007, or (2) the exception in Sec. 203.31(b) applies. In
both situations, your lease must be partly or entirely in less than 200
meters of water and production must begin on this well before May 3,
2009. If drilling of the second well began on or after May 18, 2007, the
second well would be qualified as a phase 2 or phase 3 ultra-deep well
and, unless the exception in Sec. 203.31(b) applies, would not earn any
additional RSV (as prescribed in Sec. 203.30), so the total RSV for
your lease would remain at 15 BCF.
Example 6: If you have a qualified deep well that is a sidetrack,
with a perforated interval the top of which is 16,000 feet TVD SS and a
sidetrack measured depth of 4,000 feet, and later drill a second
qualified well that is a sidetrack, with a perforated interval the top
of which is 19,000 feet TVD SS and a sidetrack measured depth of 8,000
feet, we increase the total RSV for your lease from 6.4 BCF [4 + (600 *
4,000)/1,000,000] to 15.2 BCF {6.4 + [4 + (600 * 8,000)/
1,000,000)]{time} under paragraphs (b)(2) and (c)(3) of this section.
We would apply that RSV to gas production from all qualified wells on
your lease, as prescribed in Sec. Sec. 203.43 and 203.48. The
difference of 8.8 BCF represents the RSV earned by the second sidetrack
that has a perforated interval the top of which is deeper than 18,000
feet TVD SS.

Sec. 203.42 What conditions and limitations apply to royalty relief
for deep wells and phase 1 ultra-deep wells?

The conditions and limitations in the following table apply to
royalty relief under Sec. 203.41.

------------------------------------------------------------------------
If . . . Then . . .
------------------------------------------------------------------------
(a) Your lease has produced gas or oil your lease cannot earn an
from a well with a perforated interval RSV under Sec. 203.41 as
the top of which is 18,000 feet TVD SS or a result of drilling any
deeper, subsequent deep wells or
phase 1 ultra-deep wells.
(b) You determine RSV under Sec. 203.41 that determination
for the first qualified deep well or establishes the total RSV
qualified phase 1 ultra-deep well on your available for that drilling
lease (whether an original well or a depth interval on your
sidetrack) because you drilled and lease (i.e., either 15,000-
produced it within the time intervals set 18,000 feet TVD SS, or
forth in the definitions for qualified 18,000 feet TVD SS and
wells, deeper), regardless of the
number of subsequent
qualified wells you drill
to that depth interval.
(c) A qualified deep well or qualified the RSV earned by that well
phase 1 ultra-deep well on your lease is under Sec. 203.41 applies
within a unitized portion of your lease, only to production from
qualified wells on or
allocated to your lease and
not to other leases within
the unit.
(d) Your qualified deep well or qualified the lease with the
phase 1 ultra-deep well is a directional perforated interval that
well (either an original well or a initially produces earns
sidetrack) drilled across a lease line, the RSV. However, if the
perforated interval crosses
a lease line, the lease
where the surface of the
well is located earns the
RSV.
(e) You earn an RSV under Sec. 203.41, that RSV is in addition to
any RSS for your lease
under Sec. 203.45 that
results from a different
wellbore.
(f) Your lease earns an RSV under Sec. the RSV is not forfeited or
203.41 and later produces from a well terminated, but you may not
that is not a qualified well, apply the RSV under Sec.
203.41 to production from
the non-qualified well.
(g) You qualify for an RSV under you still owe minimum
paragraphs (b) or (c) of Sec. 203.41, royalties or rentals in
accordance with your lease
terms.

[[Page 23]]

(h) You transfer your lease, unused RSVs transfer to a
successor lessee and expire
with the lease.
------------------------------------------------------------------------

Example to paragraph (b): If your first qualified deep well is a
sidetrack with a perforated interval whose top is 16,000 feet TVD SS and
earns an RSV of 12.5 BCF, and you later drill a qualified original deep
well to 17,000 feet TVD SS, the RSV for your lease remains at 12.5 BCF
and does not increase to 15 BCF. However, under paragraph (c) of Sec.
203.41, if you subsequently drill a qualified deep well to a depth of
18,000 feet or greater TVD SS, you may earn an additional RSV.

Sec. 203.43 To which production do I apply the RSV earned
from qualified deep wells or qualified phase 1 ultra-deep wells on my lease?

(a) You must apply the RSV prescribed in Sec. 203.41(b) and (c) to
gas volumes produced from qualified wells on or after May 3, 2004,
reported on the OGOR-A for your lease under 30 CFR 1210.102, as and to
the extent prescribed in Sec. Sec. 203.43 and 203.48.
(1) Except as provided in paragraph (a)(2) of this section, all gas
production from qualified wells reported on the OGOR-A, including
production that is not subject to royalty, counts toward the lease RSV.
(2) Production to which an RSS applies under Sec. Sec. 203.45 and
203.46 does not count toward the lease RSV.
(b) This paragraph applies to any lease with a qualified deep well
or qualified phase 1 ultra-deep well when no part of the lease is within
a BSEE-approved unit. Subject to the price conditions in Sec. 203.48,
you must apply the RSV prescribed in Sec. 203.41 as required under the
following paragraphs (b)(1) and (b)(2) of this section.
(1) You must apply the RSV to the earliest gas production occurring
on and after the later of:
(i) May 3, 2004, for an RSV earned by a qualified deep well or
qualified phase 1 ultra-deep well on a lease that is located entirely or
partly in water less than 200 meters deep;
(ii) May 18, 2007, for an RSV earned by a qualified deep well on a
lease that is located entirely in water more than 200 meters deep; or
(iii) The date that the first qualified well that earns your lease
the RSV begins production (other than test production).
(2) You must apply the RSV to only gas production from qualified
wells on your lease, regardless of their depth, for which you have met
the requirements in Sec. 203.35 or Sec. 203.44.

Example 1: On a lease in water less than 200 meters deep, you began
drilling an original deep well with a perforated interval the top of
which is 18,200 feet TVD SS in September 2003, that became a qualified
deep well in July 2004, when it began producing and using the RSV that
it earned. You subsequently drill another original deep well with a
perforated interval the top of which is 16,600 feet TVD SS, which
becomes a qualified deep well when production begins in August 2008. The
first well earned an RSV of 25 BCF (see Sec. 203.41(a)(1) and (b)(3)).
You must apply any remaining RSV each month beginning in August 2008 to
production from both wells until the 25 BCF RSV is fully utilized
according to paragraph (b)(2) of this section. If the second well had
begun production in August 2009, it would not be a qualified deep well
because it started production after expiration in May 2009 of the
ability to qualify for royalty relief in this water depth, and could not
share any of the remaining RSV (see definition of a qualified deep well
in Sec. 203.0).
Example 2: On a lease in water between 200 and 400 meters deep, you
begin drilling an original deep well with a perforated interval the top
of which is 17,100 feet TVD SS in November 2010 that becomes a qualified
deep well in June 2011 when it begins producing and using the RSV. You
subsequently drill another original deep well with a perforated interval
the top of which is 15,300 feet TVD SS which becomes a qualified deep
well by beginning production in October 2011 (see definition of a
qualified deep well in Sec. 203.0). Only the first well earns an RSV
equal to 15 BCF (see Sec. 203.41(a) and (b)). You must apply any
remaining RSV each month beginning in October 2011 to production from
both qualified deep wells until the 15 BCF RSV is fully utilized
according to paragraph (b)(2) of this section.

(c) This paragraph applies to any lease with a qualified deep well
or qualified phase 1 ultra-deep well when all or part of the lease is
within a BSEE-approved unit. Under the unit agreement, a share of the
production from all the qualified wells in the unit

[[Page 24]]

participating area would be allocated to your lease each month according
to the participating area percentages. Subject to the price conditions
in Sec. 203.48, you must apply the RSV prescribed under Sec. 203.41 as
required under the following paragraphs (c)(1) through (3) of this
section.
(1) You must apply the RSV to the earliest gas production occurring
on and after the later of:
(i) May 3, 2004, for an RSV earned by a qualified well or qualified
phase 1 ultra-deep well on a lease that is located entirely or partly in
water less than 200 meters deep;
(ii) May 18, 2007, for an RSV earned by a qualified deep well on a
lease that is located entirely in water more than 200 meters deep; or
(iii) The date that the first qualified well that earns your lease
the RSV begins production (other than test production).
(2) You must apply the RSV to only gas production:
(i) From all qualified wells on the non-unitized area of your lease,
regardless of their depth, for which you have met the requirements in
Sec. 203.35 or Sec. 203.44; and,
(ii) Allocated to your lease under a BSEE-approved unit agreement
from qualified wells on unitized areas of your lease and on unitized
areas of other leases in the unit, regardless of their depth, for which
the requirements in Sec. 203.35 or Sec. 203.44 have been met.
(3) The allocated share under paragraph (c)(2)(ii) of this section
does not increase the RSV for your lease. None of the volumes produced
from a well that is not within a unit participating area may be
allocated to other leases in the unit.

Example: The east half of your lease A is unitized with all of lease
B. There is one qualified 19,000-foot TVD SS deep well on the non-
unitized portion of lease A, one qualified 18,500-foot TVD SS deep well
on the unitized portion of lease A, and a qualified 19,400-foot TVD SS
deep well on lease B. The participating area percentages allocate 32
percent of production from both of the unit qualified deep wells to
lease A and 68 percent to lease B. If the non-unitized qualified deep
well on lease A produces 12 BCF and the unitized qualified deep well on
lease A produces 15 BCF, and the qualified deep well on lease B produces
10 BCF, then the production volume from and allocated to lease A to
which the lease an RSV applies is 20 BCF [12 + (15 + 10) * (0.32)]. The
production volume allocated to lease B to which the lease B RSV applies
is 17 BCF [(15 + 10) * (0.68)].

(d) You must begin paying royalties when the cumulative production
of gas from all qualified wells on your lease, or allocated to your
lease under paragraph (c) of this section, reaches the applicable RSV
allowed under Sec. 203.31 or Sec. 203.41. For the month in which
cumulative production reaches this RSV, you owe royalties on the portion
of gas production that exceeds the RSV remaining at the beginning of
that month.
(e) You may not apply the RSV allowed under Sec. 203.41 to:
(1) Production from completions less than 15,000 feet TVD SS, except
in cases where the qualified deep well is re-perforated in the same
reservoir previously perforated deeper than 15,000 feet TVD SS;
(2) Production from a deep well or phase 1 ultra-deep well on any
other lease, except as provided in paragraph (c) of this section;
(3) Any liquid hydrocarbon (oil and condensate) volumes; or
(4) Production from a deep well or phase 1 ultra-deep well that
commenced drilling before:
(i) March 26, 2003, on a lease that is located entirely or partly in
water less than 200 meters deep, or
(ii) May 18, 2007, on a lease that is located entirely in water more
than 200 meters deep.

Sec. 203.44 What administrative steps must I take to use
the royalty suspension volume?

(a) You must notify the BSEE Regional Supervisor for Production and
Development in writing of your intent to begin drilling operations on
all deep wells and phase 1 ultra-deep wells; and
(b) Within 30 days of the beginning of production from all wells
that would become qualified wells by satisfying the requirements of this
section, you must:
(1) Provide written notification to the BSEE Regional Supervisor for
Production and Development that production has begun; and

[[Page 25]]

(2) Request confirmation of the size of the royalty suspension
volume earned by your lease.
(c) Before beginning production, you must meet any production
measurement requirements that the BSEE Regional Supervisor for
Production and Development has determined are necessary under 30 CFR
part 250, subpart L.
(d) You must provide the information in paragraph (b) of this
section by January 20, 2009, if you produced before December 18, 2008,
from a qualified deep well or qualified phase 1 ultra-deep well on a
lease that is located entirely in water more than 200 meters and less
than 400 meters deep.
(e) The BSEE Regional Supervisor for Production and Development may
extend the deadline for beginning production for up to one year for a
well that cannot begin production before the applicable date prescribed
in the definition of ``qualified deep well'' in Sec. 203.0 if it meets
all of the following criteria.
(1) The well otherwise meets the criteria in the definition of a
qualified deep well in Sec. 203.0.
(2) The delay in production occurred after reaching total depth in
the well.
(3) Production (other than test production) was expected to begin
from the well before the applicable deadline in the definition of a
qualified deep well in Sec. 203.0. You must provide a credible activity
schedule with supporting documentation.
(4) The delay in beginning production is for reasons beyond your
control, such as adverse weather and accidents which BSEE deems were
unavoidable.

Sec. 203.45 If I drill a certified unsuccessful well, what royalty relief
will my lease earn?

Your lease may earn a royalty suspension supplement. Subject to
paragraph (d) of this section, the royalty suspension supplement is in
addition to any royalty suspension volume your lease may earn under
Sec. 203.41.
(a) If you drill a certified unsuccessful well and you satisfy the
administrative requirements of Sec. 203.47, subject to the price
conditions in Sec. 203.48, your lease earns an RSS shown in the
following table. The RSS is shown in billions of cubic feet of gas
equivalent (BCFE) or in thousands of cubic feet of gas equivalent (MCFE)
and is applicable to oil and gas production as prescribed in Sec.
203.46.

------------------------------------------------------------------------
Then your lease earns an RSS
on this volume of oil and
If you have a certified unsuccessful well gas production as prescribed
that is:-- in this section and Sec.
203.46:--
------------------------------------------------------------------------
(1) An original well and your lease has 5 BCFE.
not produced gas or oil from a deep well
or an ultra-deep well,
(2) A sidetrack (with a sidetrack measured 0.8 BCFE plus 120 MCFE times
depth of at least 10,000 feet) and your sidetrack measured depth
lease has not produced gas or oil from a (rounded to the nearest 100
deep well or an ultra-deep well, feet) but no more than 5
BCFE.
(3) An original well or a sidetrack (with 2 BCFE.
a sidetrack measured depth of at least
10,000 feet) and your lease has produced
gas or oil from a deep well with a
perforated interval the top of which is
from 15,000 to less than 18,000 feet TVD
SS,
------------------------------------------------------------------------

(b) This paragraph applies to oil and gas volumes you report on the
OGOR-A for your lease under 30 CFR 1210.102.
(1) You must apply the RSS prescribed in paragraph (a) of this
section, in accordance with the requirements in Sec. 203.46, to all oil
and gas produced from the lease:
(i) On or after December 18, 2008, if your lease is located in water
more than 200 meters but less than 400 meters deep; or
(ii) On or after May 3, 2004, if your lease is located in water
partly or entirely less than 200 meters deep.
(2) Production to which an RSV applies under Sec. Sec. 203.31
through 203.33 and Sec. Sec. 203.41 through 203.43 does not count
toward the lease RSS. All other production, including production that is
not subject to royalty, counts toward the lease RSS.

Example 1: If you drill a certified unsuccessful well that is an
original well to a target 19,000 feet TVD SS, your lease earns an RSS of
5 BCFE that would be applied to gas

[[Page 26]]

and oil production if your lease has not previously produced from a deep
well or an ultra-deep well, or you earn an RSS of 2 BCFE of gas and oil
production if your lease has previously produced from a deep well with a
perforated interval from 15,000 to less than 18,000 feet TVD SS, as
prescribed in Sec. 203.46.
Example 2: If you drill a certified unsuccessful well that is a
sidetrack that reaches a target 19,000 feet TVD SS, that has a sidetrack
measured depth of 12,545 feet, and your lease has not produced gas or
oil from any deep well or ultra-deep well, BSEE rounds the sidetrack
measured depth to 12,500 feet and your lease earns an RSS of 2.3 BCFE of
gas and oil production as prescribed in Sec. 203.45.

(c) The conversion from oil to gas for using the royalty suspension
supplement is specified in Sec. 203.73.
(d) Each lease is eligible for up to two royalty suspension
supplements. Therefore, the total royalty suspension supplement for a
lease cannot exceed 10 BCFE.
(1) You may not earn more than one royalty suspension supplement
from a single wellbore.
(2) If you begin drilling a certified unsuccessful well on one lease
but the completion target is on a second lease, the entire royalty
suspension supplement belongs to the second lease. However, if the
target straddles a lease line, the lease where the surface of the well
is located earns the royalty suspension supplement.
(e) If the same wellbore that earns an RSS as a certified
unsuccessful well later produces from a perforated interval the top of
which is 15,000 feet TVD or deeper and becomes a qualified well, it will
be subject to the following conditions:
(1) Beginning on the date production starts, you must stop applying
the royalty suspension supplement earned by that wellbore to your lease
production.
(2) If the completion of this qualified well is on your lease or, in
the case of a directional well, is on another lease, then you must
subtract from the royalty suspension volume earned by that qualified
well the royalty suspension supplement amounts earned by that wellbore
that have already been applied either on your lease or any other lease.
The difference represents the royalty suspension volume earned by the
qualified well.
(f) If the same wellbore that earned a royalty suspension supplement
later has a sidetrack drilled from that wellbore, you are not required
to subtract any royalty suspension supplement earned by that wellbore
from the royalty suspension volume that may be earned by the sidetrack.
(g) You owe minimum royalties or rentals in accordance with your
lease terms notwithstanding any royalty suspension supplements under
this section.

Sec. 203.46 To which production do I apply the royalty suspension
supplements from drilling one or two certified unsuccessful wells on my lease?

(a) Subject to the requirements of Sec. Sec. 203.40, 203.43,
203.45, 203.47, and 203.48 you must apply an RSS in Sec. 203.45 to the
earliest oil and gas production:
(1) Occurring on and after the day you file the information under
Sec. 203.47(b),
(2) From, or allocated under a BSEE-approved unit agreement to, the
lease on which the certified unsuccessful well was drilled, without
regard to the drilling depth of the well producing the gas or oil.
(b) If you have a royalty suspension volume for the lease under
Sec. 203.41, you must use the royalty suspension volumes for gas
produced from qualified wells on the lease before using royalty
suspension supplements for gas produced from qualified wells.

Example to paragraph (b): You have two shallow oil wells on your
lease. Then you drill a certified unsuccessful well and earn a royalty
suspension supplement of 5 BCFE. Thereafter, you begin production from
an original well that is a qualified well that earns a royalty
suspension volume of 15 BCF. You use only 2 BCFE of the royalty
suspension supplement before the oil wells deplete. You must use up the
15 BCF of royalty suspension volume before you use the remaining 3 BCFE
of the royalty suspension supplement for gas produced from the qualified
well.

(c) If you have no current production on which to apply the RSS
allowed under Sec. 203.45, your RSS applies to the earliest subsequent
production of gas and oil from, or allocated under a BSEE-approved unit
agreement to, your lease.

[[Page 27]]

(d) Unused royalty suspension supplements transfer to a successor
lessee and expire with the lease.
(e) You may not apply the RSS allowed under Sec. 203.45 to
production from any other lease, except for production allocated to your
lease from a BSEE-approved unit agreement. If your certified
unsuccessful well is on a lease subject to a BSEE-approved unit
agreement, the lessees of other leases in the unit may not apply any
portion of the RSS for your lease to production from the other leases in
the unit.
(f) You must begin or resume paying royalties when cumulative gas
and oil production from, or allocated under a BSEE-approved unit
agreement to, your lease (excluding any gas produced from qualified
wells subject to a royalty suspension volume allowed under Sec. 203.41)
reaches the applicable royalty suspension supplement. For the month in
which the cumulative production reaches this royalty suspension
supplement, you owe royalties on the portion of gas or oil production
that exceeds the amount of the royalty suspension supplement remaining
at the beginning of that month.

Sec. 203.47 What administrative steps do I take to obtain and use
the royalty suspension supplement?

(a) Before you start drilling a well on your lease targeted to a
reservoir at least 18,000 feet TVD SS, you must notify, in writing, the
BSEE Regional Supervisor for Production and Development of your intent
to begin drilling operations and the depth of the target.
(b) After drilling the well, you must provide the BSEE Regional
Supervisor for Production and Development within 60 days after reaching
the total depth in your well:
(1) Information that allows BSEE to confirm that you drilled a
certified unsuccessful well as defined under Sec. 203.0, including:
(i) Well log data, if your original well or sidetrack does not meet
the producibility requirements of 30 CFR part 550, subpart A; or
(ii) Well log, well test, seismic, and economic data, if your well
does meet the producibility requirements of 30 CFR part 550, subpart A;
and
(2) Information that allows BSEE to confirm the size of the royalty
suspension supplement for a sidetrack, including sidetrack measured
depth and supporting documentation.
(c) If you commenced drilling a well that otherwise meets the
criteria for a certified unsuccessful well on a lease located entirely
in more than 200 meters and entirely less than 400 meters of water on or
after May 18, 2007, and finished it before December 18, 2008, you must
provide the information in paragraph (b) of this section no later than
February 17, 2009.

Sec. 203.48 Do I keep royalty relief if prices rise significantly?

(a) You must pay royalties on all gas and oil production for which
an RSV or an RSS otherwise would be allowed under Sec. Sec. 203.40
through 203.47 for any calendar year when the average daily closing
NYMEX natural gas price exceeds the applicable threshold price shown in
the following table.

------------------------------------------------------------------------
For a lease located in The applicable threshold
water . . . And issued . . . price is . . .
------------------------------------------------------------------------
(1) Partly or entirely before December 18, $10.15 per MMBtu,
less than 200 meters 2008, adjusted annually after
deep, calendar year 2007 for
inflation.
(2) Partly or entirely after December 18, $4.55 per MMBtu, adjusted
less than 200 meters 2008, annually after calendar
deep, year 2007 for inflation
unless the lease terms
prescribe a different
price threshold.
(3) Entirely more than on any date, $4.55 per MMBtu, adjusted
200 meters and annually after calendar
entirely less than year 2007 for inflation
400 meters deep, unless the lease terms
prescribe a different
price threshold.
------------------------------------------------------------------------

(b) Determine the threshold price for any calendar year after 2007
by adjusting the threshold price in the previous year by the percentage
that the implicit price deflator for the gross domestic product, as
published by the Department of Commerce, changed during the calendar
year.
(c) You must pay any royalty due under this section no later than
March

[[Page 28]]

31 of the year following the calendar year for which you owe royalty. If
you do not pay by that date, you must pay late payment interest under 30
CFR 1218.54 from April 1 until the date of payment.
(d) Production volumes on which you must pay royalty under this
section count as part of your RSV and RSS.

Sec. 203.49 May I substitute the deep gas drilling provisions in this part
for the deep gas royalty relief provided in my lease terms?

(a) You may exercise an option to replace the applicable lease terms
for royalty relief related to deep-well drilling with those in Sec.
203.0 and Sec. Sec. 203.40 through 203.48 if you have a lease issued
with royalty relief provisions for deep-well drilling. Such leases:
(1) Must be issued as part of an OCS lease sale held after January
1, 2001, and before April 1, 2004; and
(2) Must be located wholly west of 87 degrees, 30 minutes West
longitude in the GOM entirely or partly in water less than 200 meters
deep.
(b) To exercise the option under paragraph (a) of this section, you
must notify, in writing, the BSEE Regional Supervisor for Production and
Development of your decision before September 1, 2004, or 180 days after
your lease is issued, whichever is later, and specify the lease and
block number.
(c) Once you exercise the option under paragraph (a) of this
section, you are subject to all the activity, timing, and administrative
requirements pertaining to deep gas royalty relief as specified in
Sec. Sec. 203.40 through 203.48.
(d) Exercising the option under paragraph (a) of this section is
irrevocable. If you do not exercise this option, then the terms of your
lease apply.

Royalty Relief for End-of-Life Leases

Sec. 203.50 Who may apply for end-of-life royalty relief?

You may apply for royalty relief in two situations.
(a) Your end-of-life lease (as defined in Sec. 203.2) is an oil and
gas lease and has average daily production of at least 100 barrels of
oil equivalent (BOE) per month (as calculated in Sec. 203.73) in at
least 12 of the past 15 months. The most recent of these 12 months are
considered the qualifying months. These 12 months should reflect the
basic operation you intend to use until your resources are depleted. If
you changed your operation significantly (e.g., begin re-injecting
rather than recovering gas) during the qualifying months, or if you do
so while we are processing your application, we may defer action on your
application until you revise it to show the new circumstances.
(b) Your end-of-life lease is other than an oil and gas lease (e.g.,
sulphur) and has production in at least 12 of the past 15 months. The
most recent of these 12 months are considered the qualifying months.

Sec. 203.51 How do I apply for end-of-life royalty relief?

You must submit a complete application and the required fee to the
appropriate BSEE Regional Director. Your BSEE regional office will
provide specific guidance on the report formats. A complete application
for relief includes:
(a) An administrative information report (specified in Sec. 203.83)
and
(b) A net revenue and relief justification report (specified in
Sec. 203.84).

Sec. 203.52 What criteria must I meet to get relief?

(a) To qualify for relief, you must demonstrate that the sum of
royalty payments over the 12 qualifying months exceeds 75 percent of the
sum of net revenues (before-royalty revenues minus allowable costs, as
defined in Sec. 203.84).
(b) To re-qualify for relief, e.g., either applying for additional
relief on top of relief already granted, or applying for relief sometime
after your earlier agreement terminated, you must demonstrate that:
(1) You have met the criterion listed in paragraph (a) of this
section, and
(2) The 12 required qualifying months of operation have occurred
under the current royalty arrangement.

Sec. 203.53 What relief will BSEE grant?

(a) If we approve your application and you meet certain conditions,
we

[[Page 29]]

will reduce the pre-application effective royalty rate by one-half on
production up to the relief volume amount. If you produce more than the
relief volume amount:
(1) We will impose a royalty rate equal to 1.5 times the effective
royalty rate on your additional production up to twice the relief volume
amount; and
(2) We will impose a royalty rate equal to the effective rate on all
production greater than twice the relief volume amount.
(b) Regardless of the level of production or prices (see Sec.
203.54), royalty payments due under end-of-life relief will not exceed
the royalty obligations that would have been due at the effective
royalty rate.
(1) The effective royalty rate is the average lease rate paid on
production during the 12 qualifying months.
(2) The relief volume amount is the average monthly BOE production
for the 12 qualifying months.

Sec. 203.54 How does my relief arrangement for an oil and gas lease operate
if prices rise sharply?

In those months when your current reference price rises by at least
25 percent above your base reference price, you must pay the effective
royalty rate on all monthly production.
(a) Your current reference price is a weighted average of daily
closing prices on the NYMEX for light sweet crude oil and natural gas
over the most recent full 12 calendar months;
(b) Your base reference price is a weighted average of daily closing
prices on the NYMEX for light sweet crude oil and natural gas during the
qualifying months; and
(c) Your weighting factors are the proportions of your total
production volume (in BOE) provided by oil and gas during the qualifying
months.

Sec. 203.55 Under what conditions can my end-of-life royalty
relief arrangement for an oil and gas lease be ended?

(a) If you have an end-of-life royalty relief arrangement, you may
renounce it at any time. The lease rate will return to the effective
rate during the qualifying period in the first full month following our
receipt of your renouncement of the relief arrangement.
(b) If you pay the effective lease rate for 12 consecutive months,
we will terminate your relief. The lease rate will return to the
effective rate in the first full month following this termination.
(c) We may stipulate in the letter of approval for individual cases
certain events that would cause us to terminate relief because they are
inconsistent with an end-of-life situation.

Sec. 203.56 Does relief transfer when a lease is assigned?

Yes. Royalty relief is based on the lease circumstances, not
ownership. It transfers upon lease assignment.

Royalty Relief for Pre-Act Deep Water Leases and for Development and
Expansion Projects

Sec. 203.60 Who may apply for royalty relief on a case-by-case basis
in deep water in the Gulf of Mexico or offshore of Alaska?

You may apply for royalty relief under Sec. Sec. 203.61(b) and
203.62 for an individual lease, unit or project if you:
(a) Hold a pre-Act lease (as defined in Sec. 203.0) that we have
assigned to an authorized field (as defined in Sec. 203.0);
(b) Propose an expansion project (as defined in Sec. 203.0); or
(c) Propose a development project (as defined in Sec. 203.0).

Sec. 203.61 How do I assess my chances for getting relief?

You may ask for a nonbinding assessment (a formal opinion on whether
a field would qualify for royalty relief) before turning in your first
complete application on an authorized field. This field must have a
qualifying well under 30 CFR part 550, subpart A, or be on a lease that
has allocated production under an approved unit agreement.
(a) To request a nonbinding assessment, you must:
(1) Submit a draft application in the format and detail specified in
guidance from the BSEE regional office for the GOM;
(2) Propose to drill at least one more appraisal well if you get a
favorable assessment; and
(3) Pay a fee under Sec. 203.3.

[[Page 30]]

(b) You must wait at least 90 days after receiving our assessment to
apply for relief under Sec. 203.62.
(c) This assessment is not binding because a complete application
may contain more accurate information that does not support our original
assessment. It will help you decide whether your proposed inputs for
evaluating economic viability and your supporting data and assumptions
are adequate.

Sec. 203.62 How do I apply for relief?

(a) You must send a complete application and the required fee to the
BSEE Regional Director for your region.
(b) Your application for royalty relief offshore Alaska or in deep
water in the GOM must include an original and two copies (one set of
digital information) of:
(1) Administrative information report;
(2) Economic viability and relief justification report;
(3) G&G report;
(4) Engineering report;
(5) Production report; and
(6) Cost report.
(c) Section 203.82 explains why we are authorized to require these
reports.
(d) Sections 203.81, 203.83, and 203.85 through 203.89 describe what
these reports must include. The BSEE regional office for your region
will guide you on the format for the required reports, and we encourage
you to contact this office before preparing your application for this
guidance.

Sec. 203.63 Does my application have to include all leases in the field?

(a) For authorized fields, we will accept only one joint application
for all leases that are part of the designated field on the date of
application, except as provided in paragraph (a)(3) of this section and
Sec. 203.64. However, we will evaluate all acreage that may eventually
become part of the authorized field. Therefore, if you have any other
leases that you believe may eventually be part of the authorized field,
you must submit data for these leases according to Sec. 203.81.
(1) The Regional Director maintains a Field Names Master List with
updates of all leases in each designated field.
(2) To avoid sharing proprietary data with other lessees on the
field, you may submit your proprietary G&G report separately from the
rest of your application. Your application is not complete until we
receive all the required information for each lease on the field. We
will not disclose proprietary data when explaining our assumptions and
reasons for our determinations under Sec. 203.67.
(3) We will not require a joint application if you show good cause
and honest effort to get all lessees in the field to participate. If you
must exclude a lease from your application because its lessee will not
participate, that lease is ineligible for the royalty relief for the
designated field.
(b) If your application seeks only relief for a development project
or an expansion project, your application does not have to include all
leases in the field.

Sec. 203.64 How many applications may I file on a field
or a development project?

You may file one complete application for royalty relief during the
life of the field or for a development project or an expansion project
designed to produce a reservoir or set of reservoirs. However, you may
send another application if:
(a) You are eligible to apply for a redetermination under Sec.
203.74;
(b) You apply for royalty relief for an expansion project;
(c) You withdraw the application before we make a determination; or
(d) You apply for end-of-life royalty relief.

Sec. 203.65 How long will BSEE take to evaluate my application?

(a) We will determine within 20 working days if your application for
royalty relief is complete. If your application is incomplete, we will
explain in writing what it needs. If you withdraw a complete
application, you may reapply.
(b) We will evaluate your first application on a field within 180
days, evaluate your first application on a development project or an
expansion project

[[Page 31]]

within 150 days and evaluate a redetermination under Sec. 203.75 within
120 days after we determine that it is complete.
(c) We may ask to extend the review period for your application
under the conditions in the following table.

------------------------------------------------------------------------
If . . . Then we may . . .
------------------------------------------------------------------------
(1) We need more records to audit sunk Ask to extend the 120-day or
costs, 180-day evaluation period. The
extension we request will
equal the number of days
between when you receive our
request for records and the
day we receive the records.
(2) We cannot evaluate your application Add another 30 days. We may add
for a valid reason, such as missing more than 30 days, but only if
vital information or inconsistent or you agree.
inconclusive supporting data,
(3) We need more data, explanations, or Ask to extend the 120-day or
revision, 180-day evaluation period. The
extension we request will
equal the number of days
between when you receive our
request and the day we receive
the information.
------------------------------------------------------------------------

(d) We may change your assumptions under Sec. 203.62 if our
technical evaluation reveals others that are more appropriate. We may
consult with you before a final decision and will explain any changes.
(e) We will notify all designated lease operators within a field
when royalty relief is granted.

Sec. 203.66 What happens if BSEE does not act in the time allowed?

If we do not act within the timeframes established under Sec.
203.65, you get royalty relief according to the following table.

------------------------------------------------------------------------
And we do not decide
If you apply for royalty within the time As long as you
relief for specified,
------------------------------------------------------------------------
(a) An authorized field, You get the minimum Abide by Sec. Sec.
suspension volumes 203.70 and 203.76.
specified in Sec.
203.69,
(b) An expansion project, You get a royalty Abide by Sec. Sec.
suspension for the 203.70 and 203.76.
first year of
production,
(c) A development project, You get a royalty Abide by Sec. Sec.
suspension for 203.70 and 203.76.
initial production
for the number of
months that a
decision is delayed
beyond the
stipulated
timeframes set by
Sec. 203.65, plus
all the royalty
suspension volume
for which you
qualify,
------------------------------------------------------------------------

Sec. 203.67 What economic criteria must I meet to get royalty relief
on an authorized field or project?

We will not approve applications if we determine that royalty relief
cannot make the field, development project, or expansion project
economically viable. Your field or project must be uneconomic while you
are paying royalties and must become economic with royalty relief.

Sec. 203.68 What pre-application costs will BSEE consider in determining
economic viability?

(a) We will not consider ineligible costs as set forth in Sec.
203.89(h) in determining economic viability for purposes of royalty
relief.
(b) We will consider sunk costs according to the following table.

----------------------------------------------------------------------------------------------------------------
We will . . . When determining . . .
----------------------------------------------------------------------------------------------------------------
(1) Include sunk costs, Whether a field that includes a pre-Act lease which has
not produced, other than test production, before the
application or redetermination submission date needs
relief to become economic.
(2) Not include sunk costs, Whether an authorized field, a development project, or an
expansion project can become economic with full relief
(see Sec. 203.67).
(3) Not include sunk costs, How much suspension volume is necessary to make the field,
a development project, or an expansion project economic
(see Sec. 203.69(c)).
(4) Include sunk costs for the project discovery Whether a development project or an expansion project
well on each lease, needs relief to become economic.
----------------------------------------------------------------------------------------------------------------

[[Page 32]]

Sec. 203.69 If my application is approved, what royalty relief
will I receive?

If we approve your application, subject to certain conditions, we
will not collect royalties on a specified suspension volume for your
field, development project, or expansion project. Suspension volumes
include volumes allocated to a lease under an approved unit agreement,
but exclude any volumes of production that are not normally royalty-
bearing under the lease or the regulations of this chapter (e.g., fuel
gas).
(a) For authorized fields, the minimum royalty-suspension volumes
are:
(1) 17.5 million barrels of oil equivalent (MMBOE) for fields in 200
to 400 meters of water;
(2) 52.5 MMBOE for fields in 400 to 800 meters of water; and
(3) 87.5 MMBOE for fields in more than 800 meters of water.
(b) For development projects, any relief we grant applies only to
project wells and replaces the royalty relief, if any, with which we
issued your lease.
(c) If your project is economic given the royalty relief with which
we issued your lease, we will reject the application.
(d) If the lease has earned or may earn deep gas royalty relief
under Sec. Sec. 203.40 through 203.49 or ultra-deep gas royalty relief
under Sec. Sec. 203.30 through 203.36, we will take the deep gas
royalty relief or ultra-deep gas royalty relief into account in
determining whether further royalty relief for a development project is
necessary for production to be economic.
(e) If neither paragraph (c) nor (d) of this section apply, the
minimum royalty suspension volumes are as shown in the following table:

------------------------------------------------------------------------
The minimum royalty
For . . . suspension volume is . Plus . . .
. .
------------------------------------------------------------------------
(1) RS leases in the GOM or A volume equal to the 10 percent of
leases offshore Alaska, combined royalty the median of
suspension volumes the
(or the volume distribution of
equivalent based on known
the data in your recoverable
approved application resources upon
for other forms of which BSEE
royalty suspension) based approval
with which BSEE of your
issued the leases application
participating in the from all
application that have reservoirs
or plan a well into a included in the
reservoir identified project.
in the application,
(2) Leases offshore Alaska or A volume equal to 10
other deep water GOM leases percent of the median
issued in sales after of the distribution
November 28, 2000, of known recoverable
resources upon which
BSEE based approval
of your application
from all reservoirs
included in the
project.
------------------------------------------------------------------------

(f) If your application includes pre-Act leases in different
categories of water depth, we apply the minimum royalty suspension
volume for the deepest such lease then assigned to the field. We base
the water depth and makeup of a field on the water-depth delineations in
the ``Lease Terms and Economic Conditions'' map and the ``Fields
Directory'' documents and updates in effect at the time your application
is deemed complete. These publications are available from the BSEE Gulf
of Mexico Regional Office.
(g) You will get a royalty suspension volume above the minimum if we
determine that you need more to make the field or development project
economic.
(h) For expansion projects, the minimum royalty suspension volume
equals 10 percent of the median of the distribution of known recoverable
resources upon which we based approval of your application from all
reservoirs included in your project plus any suspension volumes required
under Sec. 203.66. If we determine that your expansion project may be
economic only with more relief, we will determine and grant you the
royalty suspension volume necessary to make the project economic.
(i) The royalty suspension volume applicable to specific leases will
continue through the end of the month in which cumulative production
reaches that volume. You must calculate cumulative production from all
the leases in the authorized field or project that are entitled to share
the royalty suspension volume.

[[Page 33]]

Sec. 203.70 What information must I provide after BSEE approves relief?

You must submit reports to us as indicated in the following table.
Sections 203.81, 203.90, and 203.91 describe what these reports must
include. The BSEE Regional Office for your region will prescribe the
formats.

------------------------------------------------------------------------
Required report When due to BSEE Due date extensions
------------------------------------------------------------------------
(a) Fabricator's Within 18 months BSEE Director may
confirmation report. after approval of grant you an
relief. extension under
Sec. 203.79(c)
for up to 6 months.
(b) Post-production report. Within 120 days With acceptable
after the start of justification from
production that is you, the BSEE
subject to the Regional Director
approved royalty for your region may
suspension volume. extend the due date
up to 30 days.
------------------------------------------------------------------------

Sec. 203.71 How does BSEE allocate a field's suspension volume between
my lease and other leases on my field?

The allocation depends on when production occurs, when we issued the
lease, when we assigned it to the field, and whether we award the volume
suspension by an approved application or establish it in the lease
terms, as prescribed in this section.
(a) If your authorized field has an approved royalty suspension
volume under Sec. Sec. 203.67 and 203.69, we will suspend payment of
royalties on production from all leases in the field that participate in
the application until their cumulative production equals the approved
volume. The following conditions also apply:

------------------------------------------------------------------------
If . . . Then . . . And . . .
------------------------------------------------------------------------
(1) We assign an eligible We will not change Production from the
lease to your authorized your authorized assigned eligible
field after we approve field's royalty lease(s) counts
relief, suspension volume toward the royalty
determined under suspension volume
Sec. 203.69, for the authorized
field, but the
eligible lease will
not share any
remaining royalty
suspension volume
for the authorized
field after the
eligible lease has
produced the volume
applicable under 30
CFR 560.114.
(2) We assign a pre-Act or We will not change The assigned
post-November 2000 deep your field's lease(s) may share
water lease to your field royalty suspension in any remaining
after we approve your volume, royalty relief by
application, filing the short-
form application
specified in Sec.
203.83 and
authorized in Sec.
203.82. An
assigned RS lease
also gets any
portion of its
royalty suspension
volume remaining
even after the
field has produced
the approved relief
volume.
(3) We assign another lease In our evaluation of (i) You toll the
that you operate to your your authorized time period for
field while we are field, we will take evaluation until
evaluating your into account the you modify your
application, value of any application to be
royalty relief the consistent with the
added lease already newly constituted
has under 30 CFR field;
560.114 or its (ii) We have an
lease document. If additional 60 days
we find your to review the new
authorized field information; and
still needs (iii) The assigned
additional royalty pre-Act lease or
suspension volume, royalty suspension
that volume will be lease shares the
at least the royalty suspension
combined royalty we grant to the
suspension volume newly constituted
to which all added field. An eligible
leases on the field lease does not
are entitled, or share the royalty
the minimum suspension we grant
suspension volume to the new field.
of the authorized If you do not agree
field, whichever is to toll, we will
greater, have to reject your
application due to
incomplete
information.
Production from an
assigned eligible
lease counts toward
the royalty
suspension volume
that we grant under
Sec. 203.69 for
your authorized
field, but you will
not owe royalty on
production from the
eligible lease
until it has
produced the volume
applicable under 30
CFR 560.114.

[[Page 34]]

(4) We assign another We will change your (i) You both toll
operator's lease to your field's minimum the time period for
field while we are suspension volume evaluation until
evaluating your provided the both of you modify
application, assigned lease your application to
joins the be consistent with
application and is the new field;
entitled to a (ii) We have an
larger minimum additional 60 days
suspension volume, to review the new
information; and
(iii) The assigned
lease(s) shares the
royalty suspension
we grant to the new
field. If you (the
original applicant)
do not agree to
toll, the other
operator's lease
retains any
suspension volume
it has or may share
in any relief that
we grant by filing
the short form
application
specified in Sec.
203.83 and
authorized in Sec.
203.82.
(5) We reassign a well on a The past production For any field based
pre-Act, eligible, or from the well relief, the past
royalty suspension lease counts toward the production for that
from field A to field B, royalty suspension well will not count
volume that we toward any royalty
grant under Sec. suspension volume
203.69 to field B, that we grant under
Sec. 203.69 to
field A. Moreover,
past production
from that well will
count toward the
royalty suspension
volume applicable
for the lease under
30 CFR 560.114 if
the well is on an
eligible lease or
under 30 CFR
560.124 if the well
is on a royalty
suspension lease.
------------------------------------------------------------------------

(b) When a project has more than one lease, the royalty suspension
volume for each lease equals that lease's actual production from the
project (or production allocated under an approved unit agreement) until
total production for all leases in the project equals the project's
approved royalty suspension volume.
(c) You may receive a royalty-suspension volume only if your entire
lease is west of 87 degrees, 30 minutes West longitude. If the field
lies on both sides of this meridian, only leases located entirely west
of the meridian will receive a royalty-suspension volume.

Sec. 203.72 Can my lease receive more than one suspension volume?

Yes. You may apply for royalty relief that involves more than one
suspension volume under Sec. 203.62 in two circumstances.
(a) Each field that includes your lease may receive a separate
royalty-suspension volume, if it meets the evaluation criteria of Sec.
203.67.
(b) An expansion project on your lease may receive a separate
royalty-suspension volume, even if we have already granted a royalty-
suspension volume to the field that encompasses the project. But the
reserves associated with the project must not have been part of our
original determination, and the project must meet the evaluation
criteria of Sec. 203.67.

Sec. 203.73 How do suspension volumes apply to natural gas?

You must measure natural gas production under the royalty-suspension
volume as follows: 5.62 thousand cubic feet of natural gas, measured in
accordance with 30 CFR part 250, subpart L, equals one barrel of oil
equivalent.

Sec. 203.74 When will BSEE reconsider its determination?

You may request a redetermination after we withdraw approval or
after you renounce royalty relief, unless we withdraw approval due to
your providing false or intentionally inaccurate information. Under
certain conditions you may also request a redetermination if we deny
your application or if you want your approved royalty suspension volume
to change. In these instances, to be eligible for a redetermination, at
least one of the following four conditions must occur.
(a) You have significant new G&G data and you previously have not
either requested a redetermination or reapplied for relief after we
withdrew approval or you relinquished royalty relief. ``Significant''
means that the new G&G data:
(1) Results from drilling new wells or getting new three-dimensional
seismic data and information (but not reinterpreting old data);
(2) Did not exist at the time of the earlier application; and

[[Page 35]]

(3) Changes your estimates of gross resource size, quality, or
projected flow rates enough to materially affect the results of our
earlier determination.
(b) You demonstrate in your new application that the technology that
most efficiently develops this field or lease was not considered or
deemed feasible in the original application. Your newly proposed
technology must improve the profitability, under equivalent market
conditions, of the field or lease relative to the development system
proposed in the prior application.
(c) Your current reference price decreases by more than 25 percent
from your base reference price as calculated under this paragraph.
(1) Your current reference price is a weighted-average of daily
closing prices on the NYMEX for light sweet crude oil and natural gas
over the most recent full 12 calendar months;
(2) Your base reference price is a weighted average of daily closing
prices on the NYMEX for light sweet crude oil and natural gas for the
full 12 calendar months preceding the date of your most recently
approved application for this royalty relief; and
(3) The weighting factors are the proportions of the total
production volume (in BOE) for oil and gas associated with the most
likely scenario (identified in Sec. Sec. 203.85 and 203.88) from your
most recently approved application for this royalty relief.
(d) Before starting to build your development and production system,
you have revised your estimated development costs, and they are more
than 120 percent of the eligible development costs associated with the
most likely scenario from your most recently approved application for
this royalty relief.

Sec. 203.75 What risk do I run if I request a redetermination?

If you request a redetermination after we have granted you a
suspension volume, you could lose some or all of the previously granted
relief. This can happen because you must file a new complete application
and pay the required fee, as discussed in Sec. 203.62. We will evaluate
your application under Sec. 203.67 using the conditions prevailing at
the time of your redetermination request. In our evaluation, we may find
that you should receive a larger, equivalent, smaller, or no suspension
volume. This means we could find that you do not qualify for the amount
of relief previously granted or for any relief at all.

Sec. 203.76 When might BSEE withdraw or reduce the approved size
of my relief?

We will withdraw approval of relief for any of the following
reasons.
(a) You change the type of development system proposed in your
application (e.g., change from a fixed platform to floating production
system, or from an independent development and production system to one
with subsea wells tied back to a host production facility, etc.).
(b) You do not start building the proposed development and
production system within 18 months of the date we approved your
application, unless the BSEE Director grants you an extension under
Sec. 203.79(c). If you start building the proposed system and then
suspend its construction before completion, and you do not restart
continuous building of the proposed system within 18 months of our
approval, we will withdraw the relief we granted.
(c) Your actual development costs are less than 80 percent of the
eligible development costs estimated in your application's most likely
scenario, and you do not report that fact in your post-production
development report (Sec. 203.70). Development costs are those
expenditures defined in Sec. 203.89(b) incurred between the application
submission date and start of production. If you report this fact in the
post-production development report, you may retain the lesser of 50
percent of the original royalty suspension volume or 50 percent of the
median of the distribution of the potentially recoverable resources
anticipated in your application.
(d) We granted you a royalty-suspension volume after you qualified
for a redetermination under Sec. 203.74(c), and we find out your actual
development costs are less than 90 percent of the eligible development
costs associated with your application's most likely scenario.
Development costs are those

[[Page 36]]

expenditures defined in Sec. 203.89(b) incurred between your
application submission date and start of production.
(e) You do not send us the fabrication confirmation report or the
post-production development report, or you provide false or
intentionally inaccurate information that was material to our granting
royalty relief under this section. You must pay royalties and late-
payment interest determined under 30 U.S.C. 1721 and 30 CFR 1218.54 on
all volumes for which you used the royalty suspension. You also may be
subject to penalties under other provisions of law.

Sec. 203.77 May I voluntarily give up relief if conditions change?

Yes, you may voluntarily give up relief by sending a letter to that
effect to the BSEE Regional office for your region.

Sec. 203.78 Do I keep relief approved by BSEE under this part for my lease,
unit or project if prices rise significantly?

If prices rise above a base price threshold for light sweet crude
oil or natural gas, you must pay full royalties on production otherwise
subject to royalty relief approved by BSEE under Sec. Sec. 203.60-
203.77 for your lease, unit or project as prescribed in this section.
(a) The following table shows the base price threshold for various
types of leases, subject to paragraph (b) of this section. Note that,
for post-November 2000 deepwater leases in the GOM, price thresholds
apply on a lease basis, so different leases on the same development
project or expansion project approved for royalty relief may have
different price thresholds.

------------------------------------------------------------------------
The base price threshold is
For . . . . . .
------------------------------------------------------------------------
(1) Pre-Act leases in the GOM, set by statute.
(2) Post-November 2000 deep water leases indicated in your original
in the GOM or leases offshore of Alaska lease agreement or, if
for which the lease or Notice of Sale set none, those in the Notice
a base price threshold, of Sale under which your
lease was issued.
(3) Post-November 2000 deep water leases the threshold set by statute
in the GOM or leases offshore of Alaska for pre-Act leases.
for which the lease or Notice of Sale did
not set a base price threshold,
------------------------------------------------------------------------

(b) An exception may occur if we determine that the price thresholds
in paragraphs (a)(2) or (a)(3) of this section mean the royalty
suspension volume set under Sec. 203.69 and in lease terms would
provide inadequate encouragement to increase production or development,
in which circumstance we could specify a different set of price
thresholds on a case-by-case basis.
(c) Suppose your base oil price threshold set under paragraph (a) is
$28.00 per barrel, and the daily closing NYMEX light sweet crude oil
prices for the previous calendar year exceeds $28.00 per barrel, as
adjusted in paragraph (h) of this section. In this case, we retract the
royalty relief authorized in this subpart and you must:
(1) Pay royalties on all oil production for the previous year at the
lease stipulated royalty rate plus interest (under 30 U.S.C. 1721 and 30
CFR 1218.54) by March 31 of the current calendar year, and
(2) Pay royalties on all your oil production in the current year.
(d) Suppose your base gas price threshold set under paragraph (a) is
$3.50 per million British thermal units (Btu), and the daily closing
NYMEX light sweet crude oil prices for the previous calendar year
exceeds $3.50 per million Btu, as adjusted in paragraph (h) of this
section. In this case, we retract the royalty relief authorized in this
subpart and you must:
(1) Pay royalties on all gas production for the previous year at the
lease stipulated royalty rate plus interest (under 30 U.S.C. 1721 and 30
CFR 1218.54) by March 31 of the current calendar year, and
(2) Pay royalties on all your gas production in the current year.
(e) Production under both paragraphs (c) and (d) of this section
counts as part of the royalty-suspension volume.
(f) You are entitled to a refund or credit, with interest, of
royalties paid on any production (that counts as part of the royalty-
suspension volume):

[[Page 37]]

(1) Of oil if the arithmetic average of the closing prices for the
current calendar year is $28.00 per barrel or less, as adjusted in
paragraph (h) of this section, and
(2) Of gas if the arithmetic average of the closing natural gas
prices for the current calendar year is $3.50 per million Btu or less,
as adjusted in paragraph (h) of this section.
(g) You must follow our regulations in the Office of Natural
Resources Revenue, 30 CFR chapter XII, for receiving refunds or credits.
(h) We change the prices referred to in paragraphs (c), (d), and (f)
of this section periodically. For pre-Act leases, these prices change
during each calendar year after 1994 by the percentage that the implicit
price deflator for the gross domestic product changed during the
preceding calendar year. For post-November 2000 deepwater leases, these
prices change as indicated in the lease instrument or in the Notice of
Sale under which we issued the lease.

Sec. 203.79 How do I appeal BSEE's decisions related to royalty relief
for a deepwater lease or a development or expansion project?

(a) Once we have designated your lease as part of a field and
notified you and other affected operators of the designation, you can
request reconsideration by sending the BSEE Director a letter within 15
days that also states your reasons. The BSEE Director's response is the
final agency action.
(b) Our decisions on your application for relief from paying royalty
under Sec. 203.67 and the royalty-suspension volumes under Sec. 203.69
are final agency actions.
(c) If you cannot start construction by the deadline in Sec.
203.76(b) for reasons beyond your control (e.g., strike at the
fabrication yard), you may request an extension up to 1 year by writing
the BSEE Director and stating your reasons. The BSEE Director's response
is the final agency action.
(d) We will notify you of all final agency actions by certified
mail, return receipt requested. Final agency actions are not subject to
appeal to the Interior Board of Land Appeals under 30 CFR part 290 and
43 CFR part 4. They are judicially reviewable under section 10(a) of the
Administrative Procedure Act (5 U.S.C. 702) only if you file an action
within 30 days of the date you receive our decision.

Sec. 203.80 When can I get royalty relief if I am not eligible
for royalty relief under other sections in the subpart?

We may grant royalty relief when it serves the statutory purposes
summarized in Sec. 203.1 and our formal relief programs, including but
not limited to the applicable levels of the royalty suspension volumes
and price thresholds, provide inadequate encouragement to promote
development or increase production. Unless your lease lies offshore of
Alaska or wholly west of 87 degrees, 30 minutes West longitude in the
GOM, your lease must be producing to qualify for relief. Before you may
apply for royalty relief apart from our programs for end-of-life leases
or for pre-Act deep water leases and development and expansion projects,
we must agree that your lease or project has two or more of the
following characteristics:
(a) The lease has produced for a substantial period and the lessee
can recover significant additional resources. Significant additional
resources mean enough to allow production for at least a year more than
would be profitable without royalty relief.
(b) Valuable facilities (e.g., a platform or pipeline that would be
removed upon lease relinquishment) exist that we do not expect a
successor lessee to use. If the facilities are located off the lease,
their preservation must depend on continued production from the lease
applying for royalty relief. We will only consider an allocable share of
costs for off-lease facilities in the relief application.
(c) A substantial risk exists that no new lessee will recover the
resources.
(d) The lessee made major efforts to reduce operating costs too
recently to use the formal program for royalty relief (e.g., recent
significant change in operations).
(e) Circumstances beyond the lessee's control, other than water
depth, preclude reliance on one of the existing royalty relief programs.

[[Page 38]]

Required Reports

Sec. 203.81 What supplemental reports do royalty-relief applications require?

(a) You must send us the supplemental reports, indicated in the
following table by an X, that apply to your field. Sections 203.83
through 203.91 describe these reports in detail.

----------------------------------------------------------------------------------------------------------------
Deep water
End-of-life --------------------------------------------------
Required reports lease Expansion Development
project Pre-act lease project
----------------------------------------------------------------------------------------------------------------
(1) Administrative information Report....... X X X X
(2) Net revenue & relief justification X ............... ...............
report.....................................
(3) Economic viability & relief ............... X X X
justification report (RSVP model inputs
justified by other required reports).......
(4) G&G report.............................. ............... X X X
(5) Engineering report...................... ............... X X X
(6) Production report....................... ............... X X X
(7) Deep water cost report.................. ............... X X X
(8) Fabricator's confirmation report........ ............... X X X
(9) Post-production development report...... ............... X X X
----------------------------------------------------------------------------------------------------------------

(b) You must certify that all information in your application,
fabricator's confirmation and post-production development reports is
accurate, complete, and conforms to the most recent content and
presentation guidelines available from the BSEE Regional office for your
region.
(c) With your application and post-production development report,
you must submit an additional report prepared by an independent CPA
that:
(1) Assesses the accuracy of the historical financial information in
your report; and
(2) Certifies that the content and presentation of the financial
data and information conform to our most recent guidelines on royalty
relief. This means the data and information must:
(i) Include only eligible costs that are incurred during the
qualification months; and
(ii) Be shown in the proper format.
(d) You must identify the people in the CPA firm who prepared the
reports referred to in paragraph (c) of this section and make them
available to us to respond to questions about the historical financial
information. We may also further review your records to support this
information.

Sec. 203.82 What is BSEE's authority to collect this information?

The Office of Management and Budget (OMB) approved the information
collection requirements in part 203 under 44 U.S.C. 3501 et seq., and
assigned OMB control number 1010-0071.
(a) We use the information to determine whether royalty relief will
result in production that wouldn't otherwise occur. We rely largely on
your information to make these determinations.
(1) Your application for royalty relief must contain enough
information on finances, economics, reservoirs, G&G characteristics,
production, and engineering estimates for us to determine whether:
(i) We should grant relief under the law, and
(ii) The requested relief will ultimately recover more resources and
return a reasonable profit on project investments.
(2) Your fabricator confirmation and post-production development
reports must contain enough information for us to verify that your
application reasonably represented your plans.
(b) Applicants (respondents) are Federal OCS oil and gas lessees.
Applications are required to obtain or retain a benefit. Therefore, if
you apply for royalty relief, you must provide this information. We will
protect information considered proprietary under applicable law and
under regulations at Sec. 203.63 and 30 CFR part 250.
(c) The Paperwork Reduction Act of 1995 requires us to inform you
that we may not conduct or sponsor, and you are not required to respond
to, a collection of information unless it displays a currently valid OMB
control number.

[[Page 39]]

(d) Send comments regarding any aspect of the collection of
information under this part, including suggestions for reducing the
burden, to the Information Collection Clearance Officer, Bureau of
Safety and Environmental Enforcement, 45600 Woodland Road, Sterling, VA
20166.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36148, June 6, 2016]

Sec. 203.83 What is in an administrative information report?

This report identifies the field or lease for which royalty relief
is requested and must contain the following items:
(a) The field or lease name;
(b) The serial number of leases we have assigned to the field, names
of the lease title holders of record, the lease operators, and whether
any lease is part of a unit;
(c) Well number, API number, location, and status of each well that
has been drilled on the field or lease or project (not required for non-
oil and gas leases);
(d) The location of any new wells proposed under the terms of the
application (not required for non-oil and gas leases);
(e) A description of field or lease history;
(f) Full information as to whether you will pay royalties or a share
of production to anyone other than the United States, the amount you
will pay, and how much you will reduce this payment if we grant relief;
(g) The type of royalty relief you are requesting;
(h) Confirmation that BOEM approved a DOCD or supplemental DOCD
(Deep Water expansion project applications only); and
(i) A narrative description of the development activities associated
with the proposed capital investments and an explanation of proposed
timing of the activities and the effect on production (Deep Water
applications only).

Sec. 203.84 What is in a net revenue and relief justification report?

This report presents cash flow data for 12 qualifying months, using
the format specified in the ``Guidelines for the Application, Review,
Approval, and Administration of Royalty Relief for End-of-Life Leases'',
U.S. Department of the Interior, BSEE. Qualifying months for an oil and
gas lease are the most recent 12 months out of the last 15 months that
you produced at least 100 BOE per day on average. Qualifying months for
other than oil and gas leases are the most recent 12 of the last 15
months having some production.
(a) The cash flow table you submit must include historical data for:
(1) Lease production subject to royalty;
(2) Total revenues;
(3) Royalty payments out of production;
(4) Total allowable costs; and
(5) Transportation and processing costs.
(b) Do not include in your cash flow table the non-allowable costs
listed at 30 CFR 1220.013 or:
(1) OCS rental payments on the lease(s) in the application;
(2) Damages and losses;
(3) Taxes;
(4) Any costs associated with exploratory activities;
(5) Civil or criminal fines or penalties;
(6) Fees for your royalty relief application; and
(7) Costs associated with existing obligations (e.g., royalty
overrides or other forms of payment for acquiring the lease,
depreciation on previously acquired equipment or facilities).
(c) We may, in reviewing and evaluating your application, disallow
costs when you have not shown they are necessary to operate the lease,
or if they are inconsistent with end-of-life operations.

Sec. 203.85 What is in an economic viability and relief justification report?

This report should show that your project appears economic without
royalties and sunk costs using the RSVP model we provide. The format of
the report and the assumptions and parameters we specify are found in
the ``Guidelines for the Application, Review, Approval and
Administration of the Deep Water Royalty Relief Program,'' U.S.
Department of the Interior, BSEE. Clearly justify each parameter you set
in every scenario you

[[Page 40]]

specify in the RSVP. You may provide supplemental information, including
your own model and results. The economic viability and relief
justification report must contain the following items for an oil and gas
lease.
(a) Economic assumptions we provide which include:
(1) Starting oil and gas prices;
(2) Real price growth;
(3) Real cost growth or decline rate, if any;
(4) Base year;
(5) Range of discount rates; and
(6) Tax rate (for use in determining after-tax sunk costs).
(b) Analysis of projected cash flow (from the date of the
application using annual totals and constant dollar values) which shows:
(1) Oil and gas production;
(2) Total revenues;
(3) Capital expenditures;
(4) Operating costs;
(5) Transportation costs; and
(6) Before-tax net cash flow without royalties, overrides, sunk
costs, and ineligible costs.
(c) Discounted values which include:
(1) Discount rate used (selected from within the range we specify).
(2) Before-tax net present value without royalties, overrides, sunk
costs, and ineligible costs.
(d) Demonstrations that:
(1) All costs, gross production, and scheduling are consistent with
the data in the G&G, engineering, production, and cost reports
(Sec. Sec. 203.86 through 203.89) and
(2) The development and production scenarios provided in the various
reports are consistent with each other and with the proposed development
system. You can use up to three scenarios (conservative, most likely,
and optimistic), but you must link each to a specific range on the
distribution of resources from the RSVP Resource Module.

Sec. 203.86 What is in a G&G report?

This report supports the reserve and resource estimates used in the
economic evaluation and must contain each of the following elements.
(a) Seismic data which includes:
(1) Non-interpreted 2D/3D survey lines reflecting any available
state-of-the-art processing technique in a format readable by BSEE and
specified by the deep water royalty relief guidelines;
(2) Interpreted 2D/3D seismic survey lines reflecting any available
state-of-the-art processing technique identifying all known and
prospective pay horizons, wells, and fault cuts;
(3) Digital velocity surveys in the format of the GOM region's
letter to lessees of 10/1/90;
(4) Plat map of ``shot points;'' and
(5) ``Time slices'' of potential horizons.
(b) Well data which includes:
(1) Hard copies of all well logs in which--
(i) The 1-inch electric log shows pay zones and pay counts and
lithologic and paleo correlation markers at least every 500-feet,
(ii) The 1-inch type log shows missing sections from other logs
where faulting occurs,
(iii) The 5-inch electric log shows pay zones and pay counts and
labeled points used in establishing resistivity of the formation, 100
percent water saturated (Ro) and the resistivity of the
undisturbed formation (Rt), and
(iv) The 5-inch porosity logs show pay zones and pay counts and
labeled points used in establishing reservoir porosity or labeled points
showing values used in calculating reservoir porosity such as bulk
density or transit time;
(2) Digital copies of all well logs spudded before December 1, 1995;
(3) Core data, if available;
(4) Well correlation sections;
(5) Pressure data;
(6) Production test results;
(7) Pressure-volume-temperature analysis, if available; and
(8) A table listing the wells and completions, and indicating which
sands and fault blocks will be targeted for completion or recompletion.
(c) Map interpretations which includes for each reservoir in the
field:
(1) Structure maps consisting of top and base of sand maps showing
well and seismic shot point locations;
(2) Isopach maps for net sand, net oil, net gas, all with well
locations;

[[Page 41]]

(3) Maps indicating well surface and bottom hole locations, location
of development facilities, and shot points; and
(4) An explanation for excluding the reservoirs you are not planning
to develop.
(d) Reservoir-specific data which includes:
(1) Probability of reservoir occurrence with hydrocarbons;
(2) Probability the hydrocarbon in the reservoir is all oil and the
probability it is all gas;
(3) Distributions or point estimates (accompanied by explanations of
why distributions less appropriately reflect the uncertainty) for the
parameters used to estimate reservoir size, i.e., acres and net
thickness;
(4) Most likely values for porosity, salt water saturation, volume
factor for oil formation, and volume factor for gas formation;
(5) Distributions or point estimates (accompanied by explanations of
why distributions less appropriately reflect the uncertainty) for
recovery efficiency (in percent) and oil or gas recovery (in stock-tank-
barrels per acre-foot or in thousands of cubic feet per acre foot);
(6) A gas/oil ratio distribution or point estimate (accompanied by
explanations of why distributions less appropriately reflect the
uncertainty) for each reservoir;
(7) A yield distribution or point estimate (accompanied by
explanations of why distributions less appropriately reflect the
uncertainty) for each gas reservoir; and
(8) Reserve or resource distribution by reservoir.
(e) Aggregated reserve and resource data which includes:
(1) The aggregated distributions for reserves and resources (in BOE)
and oil fraction for your field computed by the resource module of our
RSVP model;
(2) A description of anticipated hydrocarbon quality (i.e., specific
gravity); and
(3) The ranges within the aggregated distribution for reserves and
resources that define the development and production scenarios presented
in the engineering and production reports. Typically there will be three
ranges specified by two positive reserve and resource points on the
aggregated distribution. The range at the low end of the distribution
will be associated with the conservative development and production
scenario; the middle range will be related to the most likely
development and production scenario; and, the high end range will be
consistent with the optimistic development and production scenario.

Sec. 203.87 What is in an engineering report?

This report defines the development plan and capital requirements
for the economic evaluation and must contain the following elements.
(a) A description of the development concept (e.g., tension leg
platform, fixed platform, floater type, subsea tieback, etc.) which
includes:
(1) Its size along with basic design specifications and drawings;
and
(2) The construction schedule.
(b) An identification of planned wells which includes:
(1) The number;
(2) The type (platform, subsea, vertical, deviated, horizontal);
(3) The well depth;
(4) The drilling schedule;
(5) The kind of completion (single, dual, horizontal, etc.); and
(6) The completion schedule.
(c) A description of the production system equipment which includes:
(1) The production capacity for oil and gas and a description of
limiting component(s);
(2) Any unusual problems (low gravity, paraffin, etc.);
(3) All subsea structures;
(4) All flowlines; and
(5) Schedule for installing the production system.
(d) A discussion of any plans for multi-phase development which
includes the conceptual basis for developing in phases and goals or
milestones required for starting later phases.
(e) A set of development scenarios consisting of activity timing and
scale associated with each of up to three production profiles
(conservative, most likely, optimistic) provided in the production
report for your field (Sec. 203.88). Each development scenario and
production profile must denote the likely

[[Page 42]]

events should the field size turn out to be within a range represented
by one of the three segments of the field size distribution. If you send
in fewer than three scenarios, you must explain why fewer scenarios are
more efficient across the whole field size distribution.

Sec. 203.88 What is in a production report?

This report supports your development and production timing and
product quality expectations and must contain the following elements.
(a) Production profiles by well completion and field that specify
the actual and projected production by year for each of the following
products: oil, condensate, gas, and associated gas. The production from
each profile must be consistent with a specific level of reserves and
resources on the aggregated distribution of field size.
(b) Production drive mechanisms for each reservoir.

Sec. 203.89 What is in a cost report?

This report lists all actual and projected costs for your field,
must explain and document the source of each cost estimate, and must
identify the following elements.
(a) Sunk costs. Report sunk costs in dollars not adjusted for
inflation and only if you have documentation.
(b) Appraisal, delineation and development costs. Base them on
actual spending, current authorization for expenditure, engineering
estimates, or analogous projects. These costs cover:
(1) Platform well drilling and average depth;
(2) Platform well completion;
(3) Subsea well drilling and average depth;
(4) Subsea well completion;
(5) Production system (platform); and
(6) Flowline fabrication and installation.
(c) Production costs based on historical costs, engineering
estimates, or analogous projects. These costs cover:
(1) Operation;
(2) Equipment; and
(3) Existing royalty overrides (we will not use the royalty
overrides in evaluations).
(d) Transportation costs, based on historical costs, engineering
estimates, or analogous projects. These costs cover:
(1) Oil or gas tariffs from pipeline or tankerage;
(2) Trunkline and tieback lines; and
(3) Gas plant processing for natural gas liquids.
(e) Abandonment costs, based on historical costs, engineering
estimates, or analogous projects. You should provide the costs to plug
and abandon only wells and to remove only production systems for which
you have not incurred costs as of the time of application submission.
You should also include a point estimate or distribution of prospective
salvage value for all potentially reusable facilities and materials,
along with the source and an explanation of the figures provided.
(f) A set of cost estimates consistent with each one of up to three
field-development scenarios and production profiles (conservative, most
likely, optimistic). You should express costs in constant real dollar
terms for the base year. You may also express the uncertainty of each
cost estimate with a minimum and maximum percentage of the base value.
(g) A spending schedule. You should provide costs for each year (in
real dollars) for each category in paragraphs (a) through (f) of this
section.
(h) A summary of other costs which are ineligible for evaluating
your need for relief. These costs cover:
(1) Expenses before first discovery on the field;
(2) Cash bonuses;
(3) Fees for royalty relief applications;
(4) Lease rentals, royalties, and payments of net profit share and
net revenue share;
(5) Legal expenses;
(6) Damages and losses;
(7) Taxes;
(8) Interest or finance charges, including those embedded in
equipment leases;
(9) Fines or penalties; and
(10) Money spent on previously existing obligations (e.g., royalty
overrides or other forms of payment for acquiring a financial position
in a lease, expenditures for plugging wells and removing and abandoning
facilities that

[[Page 43]]

existed on the application submission date).

Sec. 203.90 What is in a fabricator's confirmation report?

This report shows you have committed in a timely way to the approved
system for production. This report must include the following (or its
equivalent for unconventionally acquired systems):
(a) A copy of the contract(s) under which the fabrication yard is
building the approved system for you;
(b) A letter from the contractor building the system to the BSEE
Regional Director for your region certifying when construction started
on your system; and
(c) Evidence of an appropriate down payment or equal action that
you've started acquiring the approved system.

Sec. 203.91 What is in a post-production development report?

For each cost category in the deep water cost report, you must
compare actual costs up to the date when production starts to your
planned pre-production costs. If your application included more than one
development scenario, you need to compare actual costs with those in
your scenario of most likely development. Also, you must have this
report certified by an independent CPA according to Sec. 203.81(c).

Subpart C--Federal and Indian Oil [Reserved]

Subpart D--Federal and Indian Gas [Reserved]

Subpart E--Solid Minerals, General [Reserved]

Subpart F [Reserved]

Subpart G--Other Solid Minerals [Reserved]

Subpart H--Geothermal Resources [Reserved]

Subpart I--OCS Sulfur [Reserved]

PART 219 [RESERVED]

[[Page 44]]

SUBCHAPTER B_OFFSHORE

PART 250_OIL AND GAS AND SULPHUR OPERATIONS IN THE OUTER CONTINENTAL SHELF--
Table of Contents

Subpart A_General

Authority and Definition of Terms

Sec.
250.101 Authority and applicability.
250.102 What does this part do?
250.103 Where can I find more information about the requirements in this
part?
250.104 How may I appeal a decision made under BSEE regulations?
250.105 Definitions.

Performance Standards

250.106 What standards will the Director use to regulate lease
operations?
250.107 What must I do to protect health, safety, property, and the
environment?
250.108 What requirements must I follow for cranes and other material-
handling equipment?
250.109 What documents must I prepare and maintain related to welding?
250.110 What must I include in my welding plan?
250.111 Who oversees operations under my welding plan?
250.112 What standards must my welding equipment meet?
250.113 What procedures must I follow when welding?
250.114 How must I install, maintain, and operate electrical equipment?
250.115-250.117 [Reserved]

Gas Storage or Injection

250.118 Will BSEE approve gas injection?
250.119 [Reserved]
250.120 How does injecting, storing, or treating gas affect my royalty
payments?
250.121 What happens when the reservoir contains both original gas in
place and injected gas?
250.122 What effect does subsurface storage have on the lease term?
250.123 [Reserved]
250.124 Will BSEE approve gas injection into the cap rock containing a
sulphur deposit?

Fees

250.125 Service fees.
250.126 Electronic payment instructions.

Inspection of Operations

250.130 Why does BSEE conduct inspections?
250.131 Will BSEE notify me before conducting an inspection?
250.132 What must I do when BSEE conducts an inspection?
250.133 Will BSEE reimburse me for my expenses related to inspections?

Disqualification

250.135 What will BSEE do if my operating performance is unacceptable?
250.136 How will BSEE determine if my operating performance is
unacceptable?

Special Types of Approvals

250.140 When will I receive an oral approval?
250.141 May I ever use alternate procedures or equipment?
250.142 How do I receive approval for departures?
250.143-250.144 [Reserved]
250.145 How do I designate an agent or a local agent?
250.146 Who is responsible for fulfilling leasehold obligations?

Naming and Identifying Facilities and Wells (Does Not Include MODUs)

250.150 How do I name facilities and wells in the Gulf of Mexico Region?
250.151 How do I name facilities in the Pacific Region?
250.152 How do I name facilities in the Alaska Region?
250.153 Do I have to rename an existing facility or well?
250.154 What identification signs must I display?
250.160-250.167 [Reserved]

Suspensions

250.168 May operations or production be suspended?
250.169 What effect does suspension have on my lease?
250.170 How long does a suspension last?
250.171 How do I request a suspension?
250.172 When may the Regional Supervisor grant or direct an SOO or SOP?
250.173 When may the Regional Supervisor direct an SOO or SOP?
250.174 When may the Regional Supervisor grant or direct an SOP?
250.175 When may the Regional Supervisor grant an SOO?
250.176 Does a suspension affect my royalty payment?
250.177 What additional requirements may the Regional Supervisor order
for a suspension?

[[Page 45]]

Primary Lease Requirements, Lease Term Extensions, and Lease
Cancellations

250.180 What am I required to do to keep my lease term in effect?
250.181-250.185 [Reserved]

Information and Reporting Requirements

250.186 What reporting information and report forms must I submit?
250.187 What are BSEE's incident reporting requirements?
250.188 What incidents must I report to BSEE and when must I report
them?
250.189 Reporting requirements for incidents requiring immediate
notification.
250.190 Reporting requirements for incidents requiring written
notification.
250.191 How does BSEE conduct incident investigations?
250.192 What reports and statistics must I submit relating to a
hurricane, earthquake, or other natural occurrence?
250.193 Reports and investigations of possible violations.
250.194 How must I protect archaeological resources?
250.195 What notification does BSEE require on the production status of
wells?
250.196 Reimbursements for reproduction and processing costs.
250.197 Data and information to be made available to the public or for
limited inspection.

References

250.198 Documents incorporated by reference.
250.199 Paperwork Reduction Act statements--information collection.

Subpart B_Plans and Information

General Information

250.200 Definitions.
250.201 What plans and information must I submit before I conduct any
activities on my lease or unit?
250.202-250.203 [Reserved]
250.204 How must I protect the rights of the Federal government?
250.205 Are there special requirements if my well affects an adjacent
property?

Post-Approval Requirements for the EP, DPP, and DOCD

250.282 Do I have to conduct post-approval monitoring?

Deepwater Operations Plans (DWOP)

250.286 What is a DWOP?
250.287 For what development projects must I submit a DWOP?
250.288 When and how must I submit the Conceptual Plan?
250.289 What must the Conceptual Plan contain?
250.290 What operations require approval of the Conceptual Plan?
250.291 When and how must I submit the DWOP?
250.292 What must the DWOP contain?
250.293 What operations require approval of the DWOP?
250.294 May I combine the Conceptual Plan and the DWOP?
250.295 When must I revise my DWOP?

Subpart C_Pollution Prevention and Control

250.300 Pollution prevention.
250.301 Inspection of facilities.

Subpart D_Oil and Gas Drilling Operations

General Requirements

250.400 General requirements.
250.401-250.403 [Reserved]
250.404 What are the requirements for the crown block?
250.405 What are the safety requirements for diesel engines used on a
drilling rig?
250.406 [Reserved]
250.407 What tests must I conduct to determine reservoir
characteristics?
250.408 May I use alternative procedures or equipment during drilling
operations?
250.409 May I obtain departures from these drilling requirements?

Applying for a Permit to Drill

250.410 How do I obtain approval to drill a well?
250.411 What information must I submit with my application?
250.412 What requirements must the location plat meet?
250.413 What must my description of well drilling design criteria
address?
250.414 What must my drilling prognosis include?
250.415 What must my casing and cementing programs include?
250.416 What must I include in the diverter description?
250.417 [Reserved]
250.418 What additional information must I submit with my APD?

Casing and Cementing Requirements

250.420 What well casing and cementing requirements must I meet?
250.421 What are the casing and cementing requirements by type of casing
string?
250.422 When may I resume drilling after cementing?
250.423 What are the requirements for casing and liner installation?
250.424-250.426 [Reserved]

[[Page 46]]

250.427 What are the requirements for pressure integrity tests?
250.428 What must I do in certain cementing and casing situations?

Diverter System Requirements

250.430 When must I install a diverter system?
250.431 What are the diverter design and installation requirements?
250.432 How do I obtain a departure to diverter design and installation
requirements?
250.433 What are the diverter actuation and testing requirements?
250.434 What are the recordkeeping requirements for diverter actuations
and tests?
250.440-250.451 [Reserved]

Drilling Fluid Requirements

250.452 What are the real-time monitoring requirements for Arctic OCS
exploratory drilling operations?
250.455 What are the general requirements for a drilling fluid program?
250.456 What safe practices must the drilling fluid program follow?
250.457 What equipment is required to monitor drilling fluids?
250.458 What quantities of drilling fluids are required?
250.459 What are the safety requirements for drilling fluid-handling
areas?

Other Drilling Requirements

250.460 What are the requirements for conducting a well test?
250.461 What are the requirements for directional and inclination
surveys?
250.462 What are the requirements for well-control drills?
250.463 Who establishes field drilling rules?

Applying for a Permit To Modify and Well Records

250.465 When must I submit an Application for Permit to Modify (APM) or
an End of Operations Report to BSEE?
250.466-250.469 [Reserved]

Additional Arctic OCS Requirements

250.470 What additional information must I submit with my APD for Arctic
OCS exploratory drilling operations?
250.471 What are the requirements for Arctic OCS source control and
containment?
250.472 What are the relief rig requirements for the Arctic OCS?
250.473 What must I do to protect health, safety, property, and the
environment while operating on the Arctic OCS?

Hydrogen Sulfide

250.490 Hydrogen sulfide.

Subpart E_Oil and Gas Well-Completion Operations

250.500 General requirements.
250.501 Definition.
250.502 [Reserved]
250.503 Emergency shutdown system.
250.504 Hydrogen sulfide.
250.505 Subsea completions.
250.506-250.508 [Reserved]
250.509 Well-completion structures on fixed platforms.
250.510 Diesel engine air intakes.
250.511 Traveling-block safety device.
250.512 Field well-completion rules.
250.513 Approval and reporting of well-completion operations.
250.514 Well-control fluids, equipment, and operations.
250.515-250.517 [Reserved]
250.518 Tubing and wellhead equipment.

Casing Pressure Management

250.519 What are the requirements for casing pressure management?
250.520 How often do I have to monitor for casing pressure?
250.521 When do I have to perform a casing diagnostic test?
250.522 How do I manage the thermal effects caused by initial production
on a newly completed or recompleted well?
250.523 When do I have to repeat casing diagnostic testing?
250.524 How long do I keep records of casing pressure and diagnostic
tests?
250.525 When am I required to take action from my casing diagnostic
test?
250.526 What do I submit if my casing diagnostic test requires action?
250.527 What must I include in my notification of corrective action?
250.528 What must I include in my casing pressure request?
250.529 What are the terms of my casing pressure request?
250.530 What if my casing pressure request is denied?
250.531 When does my casing pressure request approval become invalid?

Subpart F_Oil and Gas Well-Workover Operations

250.600 General requirements.
250.601 Definitions.
250.602 [Reserved]
250.603 Emergency shutdown system.
250.604 Hydrogen sulfide.
250.605 Subsea workovers.
250.606-250.608 [Reserved]
250.609 Well-workover structures on fixed platforms.
250.610 Diesel engine air intakes.
250.611 Traveling-block safety device.
250.612 Field well-workover rules.

[[Page 47]]

250.613 Approval and reporting for well-workover operations.
250.614 Well-control fluids, equipment, and operations.
250.615 [Reserved]
250.616 Coiled tubing and snubbing operations.
250.617-250.618 [Reserved]
250.619 Tubing and wellhead equipment.
250.620 Wireline operations.

Subpart G--Well Operations and Equipment

General Requirements

250.700 What operations and equipment does this subpart cover?
250.701 May I use alternate procedures or equipment during operations?
250.702 May I obtain departures from these requirements?
250.703 What must I do to keep wells under control?

Rig Requirements

250.710 What instructions must be given to personnel engaged in well
operations?
250.711 What are the requirements for well-control drills?
250.712 What rig unit movements must I report?
250.713 What must I provide if I plan to use a mobile offshore drilling
unit (MODU) for well operations?
250.714 Do I have to develop a dropped objects plan?
250.715 Do I need a global positioning system (GPS) for all MODUs?

Well Operations

250.720 When and how must I secure a well?
250.721 What are the requirements for pressure testing casing and
liners?
250.722 What are the requirements for prolonged operations in a well?
250.723 What additional safety measures must I take when I conduct
operations on a platform that has producing wells or has other
hydrocarbon flow?
250.724 What are the real-time monitoring requirements?

Blowout Preventer (BOP) System Requirements

250.730 What are the general requirements for BOP systems and system
components?
250.731 What information must I submit for BOP systems and system
components?
250.732 What are the BSEE-approved verification organization (BAVO)
requirements for BOP systems and system components?
250.733 What are the requirements for a surface BOP stack?
250.734 What are the requirements for a subsea BOP system?
250.735 What associated systems and related equipment must all BOP
systems include?
250.736 What are the requirements for choke manifolds, kelly-type valves
inside BOPs, and drill string safety valves?
250.737 What are the BOP system testing requirements?
250.738 What must I do in certain situations involving BOP equipment or
systems?
250.739 What are the BOP maintenance and inspection requirements?

Records and Reporting

250.740 What records must I keep?
250.741 How long must I keep records?
250.742 What well records am I required to submit?
250.743 What are the well activity reporting requirements?
250.744 What are the end of operation reporting requirements?
250.745 What other well records could I be required to submit?
250.746 What are the recordkeeping requirements for casing, liner, and
BOP tests, and inspections of BOP systems and marine risers?

Subpart H_Oil and Gas Production Safety Systems

General Requirements

Sec.
250.800 General.
250.801 Safety and pollution prevention equipment (SPPE) certification.
250.802 Requirements for SPPE.
250.803 What SPPE failure reporting procedures must I follow?
250.804 Additional requirements for subsurface safety valves (SSSVs) and
related equipment installed in high pressure high temperature
(HPHT) environments.
250.805 Hydrogen sulfide.
250.806-250.809 [Reserved]

Surface and Subsurface Safety Systems--Dry Trees

250.810 Dry tree subsurface safety devices--general.
250.811 Specifications for SSSVs--dry trees.
250.812 Surface-controlled SSSVs--dry trees.
250.813 Subsurface-controlled SSSVs.
250.814 Design, installation, and operation of SSSVs--dry trees.
250.815 Subsurface safety devices in shut-in wells--dry trees.
250.816 Subsurface safety devices in injection wells--dry trees.
250.817 Temporary removal of subsurface safety devices for routine
operations.

[[Page 48]]

250.818 Additional safety equipment--dry trees.
250.819 Specification for surface safety valves (SSVs).
250.820 Use of SSVs.
250.821 Emergency action and safety system shutdown--dry trees.
250.822-250.824 [Reserved]

Subsea and Subsurface Safety Systems--Subsea Trees

250.825 Subsea tree subsurface safety devices--general.
250.826 Specifications for SSSVs--subsea trees.
250.827 Surface-controlled SSSVs--subsea trees.
250.828 Design, installation, and operation of SSSVs--subsea trees.
250.829 Subsurface safety devices in shut-in wells--subsea trees.
250.830 Subsurface safety devices in injection wells--subsea trees.
250.831 Alteration or disconnection of subsea pipeline or umbilical.
250.832 Additional safety equipment--subsea trees.
250.833 Specification for underwater safety valves (USVs).
250.834 Use of USVs.
250.835 Specification for all boarding shutdown valves (BSDVs)
associated with subsea systems.
250.836 Use of BSDVs.
250.837 Emergency action and safety system shutdown--subsea trees.
250.838 What are the maximum allowable valve closure times and hydraulic
bleeding requirements for an electro-hydraulic control system?
250.839 What are the maximum allowable valve closure times and hydraulic
bleeding requirements for a direct-hydraulic control system?

Production Safety Systems

250.840 Design, installation, and maintenance--general.
250.841 Platforms.
250.842 Approval of safety systems design and installation features.
250.843-250.849 [Reserved]

Additional Production System Requirements

250.850 Production system requirements--general.
250.851 Pressure vessels (including heat exchangers) and fired vessels.
250.852 Flowlines/Headers.
250.853 Safety sensors.
250.854 Floating production units equipped with turrets and turret-
mounted systems.
250.855 Emergency shutdown (ESD) system.
250.856 Engines.
250.857 Glycol dehydration units.
250.858 Gas compressors.
250.859 Firefighting systems.
250.860 Chemical firefighting system.
250.861 Foam firefighting systems.
250.862 Fire and gas-detection systems.
250.863 Electrical equipment.
250.864 Erosion.
250.865 Surface pumps.
250.866 Personnel safety equipment.
250.867 Temporary quarters and temporary equipment.
250.868 Non-metallic piping.
250.869 General platform operations.
250.870 Time delays on pressure safety low (PSL) sensors.
250.871 Welding and burning practices and procedures.
250.872 Atmospheric vessels.
250.873 Subsea gas lift requirements.
250.874 Subsea water injection systems.
250.875 Subsea pump systems.
250.876 Fired and exhaust heated components.
250.877-250.879 [Reserved]

Safety Device Testing

250.880 Production safety system testing.
250.881-250.889 [Reserved]

Records and Training

250.890 Records.
250.891 Safety device training.
250.892-250.899 [Reserved]

Subpart I_Platforms and Structures

General Requirements for Platforms

250.900 What general requirements apply to all platforms?
250.901 What industry standards must your platform meet?
250.902 What are the requirements for platform removal and location
clearance?
250.903 What records must I keep?

Platform Approval Program

250.904 What is the Platform Approval Program?
250.905 How do I get approval for the installation, modification, or
repair of my platform?
250.906 What must I do to obtain approval for the proposed site of my
platform?
250.907 Where must I locate foundation boreholes?
250.908 What are the minimum structural fatigue design requirements?

Platform Verification Program

250.909 What is the Platform Verification Program?
250.910 Which of my facilities are subject to the Platform Verification
Program?

[[Page 49]]

250.911 If my platform is subject to the Platform Verification Program,
what must I do?
250.912 What plans must I submit under the Platform Verification
Program?
250.913 When must I resubmit Platform Verification Program plans?
250.914 How do I nominate a CVA?
250.915 What are the CVA's primary responsibilities?
250.916 What are the CVA's primary duties during the design phase?
250.917 What are the CVA's primary duties during the fabrication phase?
250.918 What are the CVA's primary duties during the installation phase?

Inspection, Maintenance, and Assessment of Platforms

250.919 What in-service inspection requirements must I meet?
250.920 What are the BSEE requirements for assessment of fixed
platforms?
250.921 How do I analyze my platform for cumulative fatigue?

Subpart J_Pipelines and Pipeline Rights-of-Way

250.1000 General requirements.
250.1001 Definitions.
250.1002 Design requirements for DOI pipelines.
250.1003 Installation, testing, and repair requirements for DOI
pipelines.
250.1004 Safety equipment requirements for DOI pipelines.
250.1005 Inspection requirements for DOI pipelines.
250.1006 How must I decommission and take out of service a DOI pipeline?
250.1007 What to include in applications.
250.1008 Reports.
250.1009 Requirements to obtain pipeline right-of-way grants.
250.1010 General requirements for pipeline right-of-way holders.
250.1011 [Reserved]
250.1012 Required payments for pipeline right-of-way holders.
250.1013 Grounds for forfeiture of pipeline right-of-way grants.
250.1014 When pipeline right-of-way grants expire.
250.1015 Applications for pipeline right-of-way grants.
250.1016 Granting pipeline rights-of-way.
250.1017 Requirements for construction under pipeline right-of-way
grants.
250.1018 Assignment of pipeline right-of-way grants.
250.1019 Relinquishment of pipeline right-of-way grants.

Subpart K_Oil and Gas Production Requirements

General

250.1150 What are the general reservoir production requirements?

Well Tests and Surveys

250.1151 How often must I conduct well production tests?
250.1152 How do I conduct well tests?
250.1153 [Reserved]

Classifying Reservoirs

250.1154-250.1155 [Reserved]

Approvals Prior to Production

250.1156 What steps must I take to receive approval to produce within
500 feet of a unit or lease line?
250.1157 How do I receive approval to produce gas-cap gas from an oil
reservoir with an associated gas cap?
250.1158 How do I receive approval to downhole commingle hydrocarbons?

Production Rates

250.1159 May the Regional Supervisor limit my well or reservoir
production rates?

laring, Venting, and Burning Hydrocarbons

250.1160 When may I flare or vent gas?
250.1161 When may I flare or vent gas for extended periods of time?
250.1162 When may I burn produced liquid hydrocarbons?
250.1163 How must I measure gas flaring or venting volumes and liquid
hydrocarbon burning volumes, and what records must I maintain?
250.1164 What are the requirements for flaring or venting gas containing
H2S?

Other Requirements

250.1165 What must I do for enhanced recovery operations?
250.1166 What additional reporting is required for developments in the
Alaska OCS Region?
250.1167 What information must I submit with forms and for approvals?

Subpart L_Oil and Gas Production Measurement, Surface Commingling, and
Security

250.1200 Question index table.
250.1201 Definitions.
250.1202 Liquid hydrocarbon measurement.
250.1203 Gas measurement.
250.1204 Surface commingling.
250.1205 Site security.

[[Page 50]]

Subpart M_Unitization

250.1300 What is the purpose of this subpart?
250.1301 What are the requirements for unitization?
250.1302 What if I have a competitive reservoir on a lease?
250.1303 How do I apply for voluntary unitization?
250.1304 How will BSEE require unitization?

Subpart N_Outer Continental Shelf Civil Penalties

Outer Continental Shelf Lands Act Civil Penalties

250.1400 How does BSEE begin the civil penalty process?
250.1401 [Reserved]
250.1402 Definitions.
250.1403 What is the maximum civil penalty?
250.1404 Which violations will BSEE review for potential civil
penalties?
250.1405 When is a case file developed?
250.1406 When will BSEE notify me and provide penalty information?
250.1407 How do I respond to the letter of notification?
250.1408 When will I be notified of the Reviewing Officer's decision?
250.1409 What are my appeal rights?

Federal Oil and Gas Royalty Management Act Civil Penalties Definitions

250.1450 What definitions apply to this subpart?

Penalties After a Period To Correct

250.1451 What may BSEE do if I violate a statute, regulation, order, or
lease term relating to a Federal oil and gas lease?
250.1452 What if I correct the violation?
250.1453 What if I do not correct the violation?
250.1454 How may I request a hearing on the record on a Notice of
Noncompliance?
250.1455 Does my request for a hearing on the record affect the
penalties?
250.1456 May I request a hearing on the record regarding the amount of a
civil penalty if I did not request a hearing on the Notice of
Noncompliance?

Penalties Without a Period To Correct

250.1460 May I be subject to penalties without prior notice and an
opportunity to correct?
250.1461 How will BSEE inform me of violations without a period to
correct?
250.1462 How may I request a hearing on the record on a Notice of
Noncompliance regarding violations without a period to
correct?
250.1463 Does my request for a hearing on the record affect the
penalties?
250.1464 May I request a hearing on the record regarding the amount of a
civil penalty if I did not request a hearing on the Notice of
Noncompliance?

General Provisions

250.1470 How does BSEE decide what the amount of the penalty should be?
250.1471 Does the penalty affect whether I owe interest?
250.1472 How will the Office of Hearings and Appeals conduct the hearing
on the record?
250.1473 How may I appeal the Administrative Law Judge's decision?
250.1474 May I seek judicial review of the decision of the Interior
Board of Land Appeals?
250.1475 When must I pay the penalty?
250.1476 Can BSEE reduce my penalty once it is assessed?
250.1477 How may BSEE collect the penalty?

Criminal Penalties

250.1480 May the United States criminally prosecute me for violations
under Federal oil and gas leases?

Subpart O_Well Control and Production Safety Training

250.1500 Definitions.
250.1501 What is the goal of my training program?
250.1503 What are my general responsibilities for training?
250.1504 May I use alternative training methods?
250.1505 Where may I get training for my employees?
250.1506 How often must I train my employees?
250.1507 How will BSEE measure training results?
250.1508 What must I do when BSEE administers written or oral tests?
250.1509 What must I do when BSEE administers or requires hands-on,
simulator, or other types of testing?
250.1510 What will BSEE do if my training program does not comply with
this subpart?

Subpart P_Sulphur Operations

250.1600 Performance standard.
250.1601 Definitions.
250.1602 Applicability.
250.1603 Determination of sulphur deposit.
250.1604 General requirements.
250.1605 Drilling requirements.
250.1606 Control of wells.
250.1607 Field rules.
250.1608 Well casing and cementing.
250.1609 Pressure testing of casing.
250.1610 Blowout preventer systems and system components.

[[Page 51]]

250.1611 Blowout preventer systems tests, actuations, inspections, and
maintenance.
250.1612 Well-control drills.
250.1613 Diverter systems.
250.1614 Mud program.
250.1615 Securing of wells.
250.1616 Supervision, surveillance, and training.
250.1617 Application for permit to drill.
250.1618 Application for permit to modify.
250.1619 Well records.
250.1620 Well-completion and well-workover requirements.
250.1621 Crew instructions.
250.1622 Approvals and reporting of well-completion and well-workover
operations.
250.1623 Well-control fluids, equipment, and operations.
250.1624 Blowout prevention equipment.
250.1625 Blowout preventer system testing, records, and drills.
250.1626 Tubing and wellhead equipment.
250.1627 Production requirements.
250.1628 Design, installation, and operation of production systems.
250.1629 Additional production and fuel gas system requirements.
250.1630 Safety-system testing and records.
250.1631 Safety device training.
250.1632 Production rates.
250.1633 Production measurement.
250.1634 Site security.

Subpart Q_Decommissioning Activities

General

250.1700 What do the terms ``decommissioning'', ``obstructions'', and
``facility'' mean?
250.1701 Who must meet the decommissioning obligations in this subpart?
250.1702 When do I accrue decommissioning obligations?
250.1703 What are the general requirements for decommissioning?
250.1704 What decommissioning applications and reports must I submit and
when must I submit them?
250.1705 [Reserved]
250.1706 Coiled tubing and snubbing operations.
250.1707-250.1709 [Reserved]

Permanently Plugging Wells

250.1710 When must I permanently plug all wells on a lease?
250.1711 When will BSEE order me to permanently plug a well?
250.1712 What information must I submit before I permanently plug a well
or zone?
250.1713 Must I notify BSEE before I begin well plugging operations?
250.1714 What must I accomplish with well plugs?
250.1715 How must I permanently plug a well?
250.1716 To what depth must I remove wellheads and casings?
250.1717 [Reserved]

Temporary Abandoned Wells

250.1721 If I temporarily abandon a well that I plan to re-enter, what
must I do?
250.1722 If I install a subsea protective device, what requirements must
I meet?
250.1723 What must I do when it is no longer necessary to maintain a
well in temporary abandoned status?

Removing Platforms and Other Facilities

250.1725 When do I have to remove platforms and other facilities?
250.1726 When must I submit an initial platform removal application and
what must it include?
250.1727 What information must I include in my final application to
remove a platform or other facility?
250.1728 To what depth must I remove a platform or other facility?
250.1729 After I remove a platform or other facility, what information
must I submit?
250.1730 When might BSEE approve partial structure removal or toppling
in place?
250.1731 Who is responsible for decommissioning an OCS facility subject
to an Alternate Use RUE?

Site Clearance for Wells, Platforms, and Other Facilities

250.1740 How must I verify that the site of a permanently plugged well,
removed platform, or other removed facility is clear of
obstructions?
250.1741 If I drag a trawl across a site, what requirements must I meet?
250.1742 What other methods can I use to verify that a site is clear?
250.1743 How do I certify that a site is clear of obstructions?

Pipeline Decommissioning

250.1750 When may I decommission a pipeline in place?
250.1751 How do I decommission a pipeline in place?
250.1752 How do I remove a pipeline?
250.1753 After I decommission a pipeline, what information must I
submit?
250.1754 When must I remove a pipeline decommissioned in place?

Subpart R [Reserved]

Subpart S_Safety and Environmental Management Systems (SEMS)

250.1900 Must I have a SEMS program?

[[Page 52]]

250.1901 What is the goal of my SEMS program?
250.1902 What must I include in my SEMS program?
250.1903 Acronyms and definitions.
250.1904 Special instructions.
250.1905-250.1908 [Reserved]
250.1909 What are management's general responsibilities for the SEMS
program?
250.1910 What safety and environmental information is required?
250.1911 What hazards analysis criteria must my SEMS program meet?
250.1912 What criteria for management of change must my SEMS program
meet?
250.1913 What criteria for operating procedures must my SEMS program
meet?
250.1914 What criteria must be documented in my SEMS program for safe
work practices and contractor selection?
250.1915 What training criteria must be in my SEMS program?
250.1916 What criteria for mechanical integrity must my SEMS program
meet?
250.1917 What criteria for pre-startup review must be in my SEMS
program?
250.1918 What criteria for emergency response and control must be in my
SEMS program?
250.1919 What criteria for investigation of incidents must be in my SEMS
program?
250.1920 What are the auditing requirements for my SEMS program?
250.1921 What qualifications must the ASP meet?
250.1922 What qualifications must an AB meet?
250.1923 [Reserved]
250.1924 How will BSEE determine if my SEMS program is effective?
250.1925 May BSEE direct me to conduct additional audits?
250.1926 [Reserved]
250.1927 What happens if BSEE finds shortcomings in my SEMS program?
250.1928 What are my recordkeeping and documentation requirements?
250.1929 What are my responsibilities for submitting OCS performance
measure data?
250.1930 What must be included in my SEMS program for SWA?
250.1931 What must be included in my SEMS program for UWA?
250.1932 What are my EPP requirements?
250.1933 What procedures must be included for reporting unsafe working
conditions?

Authority: 30 U.S.C. 1751, 31 U.S.C. 9701, 33 U.S.C. 1321(j)(1)(C),
43 U.S.C. 1334.

Source: 76 FR 64462, Oct. 18, 2011, unless otherwise noted.

Editorial Note: Nomenclature changes to part 250 appear at 77 FR
50891, Aug. 22, 2012.

Subpart A_General

Authority and Definition of Terms

Sec. 250.101 Authority and applicability.

The Secretary of the Interior (Secretary) authorized the Bureau of
Safety and Environmental Enforcement (BSEE) to regulate oil, gas, and
sulphur exploration, development, and production operations on the Outer
Continental Shelf (OCS). Under the Secretary's authority, the Director
requires that all operations:
(a) Be conducted according to the OCS Lands Act (OCSLA), the
regulations in this part, BSEE orders, the lease or right-of-way, and
other applicable laws, regulations, and amendments; and
(b) Conform to sound conservation practice to preserve, protect, and
develop mineral resources of the OCS to:
(1) Make resources available to meet the Nation's energy needs;
(2) Balance orderly energy resource development with protection of
the human, marine, and coastal environments;
(3) Ensure the public receives a fair and equitable return on the
resources of the OCS;
(4) Preserve and maintain free enterprise competition; and
(5) Minimize or eliminate conflicts between the exploration,
development, and production of oil and natural gas and the recovery of
other resources.

Sec. 250.102 What does this part do?

(a) This part 250 contains the regulations of the BSEE Offshore
program that govern oil, gas, and sulphur exploration, development, and
production operations on the OCS. When you conduct operations on the
OCS, you must submit requests, applications, and notices, or provide
supplemental information for BSEE approval.
(b) The following table of general references shows where to look
for information about these processes.

------------------------------------------------------------------------
For information about . . . Refer to . . .
------------------------------------------------------------------------
(1) Applications for permit to drill,.. 30 CFR part 250, subpart D.
(2) Development and Production Plans 30 CFR part 550, subpart B.
(DPP),.

[[Page 53]]

(3) Downhole commingling,.............. 30 CFR part 250, subpart K.
(4) Exploration Plans (EP),............ 30 CFR part 550, subpart B.
(5) Flaring,........................... 30 CFR part 250, subpart K.
(6) Gas measurement,................... 30 CFR part 250, subpart L.
(7) Off-lease geological and 30 CFR part 551.
geophysical permits,.
(8) Oil spill financial responsibility 30 CFR part 553.
coverage,.
(9) Oil and gas production safety 30 CFR part 250, subpart H.
systems,.
(10) Oil spill response plans,......... 30 CFR part 254.
(11) Oil and gas well-completion 30 CFR part 250, subpart E.
operations,.
(12) Oil and gas well-workover 30 CFR part 250, subpart F.
operations,.
(13) Decommissioning Activities,....... 30 CFR part 250, subpart Q.
(14) Platforms and structures,......... 30 CFR part 250, subpart I.
(15) Pipelines and Pipeline Rights-of- 30 CFR part 250, subpart J and
Way,. 30 CFR part 550, subpart J.
(16) Sulphur operations,............... 30 CFR part 250, subpart P.
(17) Training,......................... 30 CFR part 250, subpart O.
(18) Unitization,...................... 30 CFR part 250, subpart M.
(19) Safety and Environmental 30 CFR part 250, subpart S.
Management Systems (SEMS),.
------------------------------------------------------------------------

[76 FR 64462, Oct. 18, 2011, as amended at 36148, June 6, 2016]

Sec. 250.103 Where can I find more information about the requirements
in this part?

BSEE may issue Notices to Lessees and Operators (NTLs) that clarify,
supplement, or provide more detail about certain requirements. NTLs may
also outline what you must provide as required information in your
various submissions to BSEE.

Sec. 250.104 How may I appeal a decision made under BSEE regulations?

To appeal orders or decisions issued under BSEE regulations in 30
CFR parts 250 to 282, follow the procedures in 30 CFR part 290.

Sec. 250.105 Definitions.

Terms used in this part will have the meanings given in the Act and
as defined in this section:
Act means the OCS Lands Act, as amended (43 U.S.C. 1331 et seq.).
Affected State means with respect to any program, plan, lease sale,
or other activity proposed, conducted, or approved under the provisions
of the Act, any State:
(1) The laws of which are declared, under section 4(a)(2) of the
Act, to be the law of the United States for the portion of the OCS on
which such activity is, or is proposed to be, conducted;
(2) Which is, or is proposed to be, directly connected by
transportation facilities to any artificial island or installation or
other device permanently or temporarily attached to the seabed;
(3) Which is receiving, or according to the proposed activity, will
receive oil for processing, refining, or transshipment that was
extracted from the OCS and transported directly to such State by means
of vessels or by a combination of means including vessels;
(4) Which is designated by the Secretary as a State in which there
is a substantial probability of significant impact on or damage to the
coastal, marine, or human environment, or a State in which there will be
significant changes in the social, governmental, or economic
infrastructure, resulting from the exploration, development, and
production of oil and gas anywhere on the OCS; or
(5) In which the Secretary finds that because of such activity there
is, or will be, a significant risk of serious damage, due to factors
such as prevailing winds and currents to the marine or coastal
environment in the event of any oil spill, blowout, or release of oil or
gas from vessels, pipelines, or other transshipment facilities.
Air pollutant means any airborne agent or combination of agents for
which the Environmental Protection Agency (EPA) has established, under
section 109 of the Clean Air Act, national primary or secondary ambient
air quality standards.
Analyzed geological information means data collected under a permit
or a lease that have been analyzed. Analysis may include, but is not
limited to, identification of lithologic and fossil content, core
analysis, laboratory analyses

[[Page 54]]

of physical and chemical properties, well logs or charts, results from
formation fluid tests, and descriptions of hydrocarbon occurrences or
hazardous conditions.
Ancillary activities mean those activities on your lease or unit
that you:
(1) Conduct to obtain data and information to ensure proper
exploration or development of your lease or unit; and
(2) Can conduct without Bureau of Ocean Energy Management (BOEM)
approval of an application or permit.
Archaeological interest means capable of providing scientific or
humanistic understanding of past human behavior, cultural adaptation,
and related topics through the application of scientific or scholarly
techniques, such as controlled observation, contextual measurement,
controlled collection, analysis, interpretation, and explanation.
Archaeological resource means any material remains of human life or
activities that are at least 50 years of age and that are of
archaeological interest.
Arctic OCS means the Beaufort Sea and Chukchi Sea Planning Areas
(for more information on these areas, see the Proposed Final OCS Oil and
Gas Leasing Program for 2012-2017 (June 2012) at http://www.boem.gov/
Oil-and-Gas-Energy-Program/Leasing/ Five-Year-Program/2012-2017/Program-
Area-Maps/index.aspx).
Arctic OCS conditions means, for the purposes of this part, the
conditions operators can reasonably expect during operations on the
Arctic OCS. Such conditions, depending on the time of year, include, but
are not limited to: Extreme cold, freezing spray, snow, extended periods
of low light, strong winds, dense fog, sea ice, strong currents, and
dangerous sea states. Remote location, relative lack of infrastructure,
and the existence of subsistence hunting and fishing areas are also
characteristic of the Arctic region.
Attainment area means, for any air pollutant, an area that is shown
by monitored data or that is calculated by air quality modeling (or
other methods determined by the Administrator of EPA to be reliable) not
to exceed any primary or secondary ambient air quality standards
established by EPA.
Best available and safest technology (BAST) means the best available
and safest technologies that the BSEE Director determines to be
economically feasible wherever failure of equipment would have a
significant effect on safety, health, or the environment.
Best available control technology (BACT) means an emission
limitation based on the maximum degree of reduction for each air
pollutant subject to regulation, taking into account energy,
environmental and economic impacts, and other costs. The Regional
Supervisor will verify the BACT on a case-by-case basis, and it may
include reductions achieved through the application of processes,
systems, and techniques for the control of each air pollutant.
Cap and flow system means an integrated suite of equipment and
vessels, including a capping stack and associated flow lines, that, when
installed or positioned, is used to control the flow of fluids escaping
from the well by conveying the fluids to the surface to a vessel or
facility equipped to process the flow of oil, gas, and water. A cap and
flow system is a high pressure system that includes the capping stack
and piping necessary to convey the flowing fluids through the choke
manifold to the surface equipment.
Capping stack means a mechanical device, including one that is pre-
positioned, that can be installed on top of a subsea or surface wellhead
or blowout preventer to stop the uncontrolled flow of fluids into the
environment.
Coastal environment means the physical, atmospheric, and biological
components, conditions, and factors that interactively determine the
productivity, state, condition, and quality of the terrestrial ecosystem
from the shoreline inward to the boundaries of the coastal zone.
Coastal zone means the coastal waters (including the lands therein
and thereunder) and the adjacent shorelands (including the waters
therein and thereunder) strongly influenced by each other and in
proximity to the shorelands of the several coastal States. The coastal
zone includes islands, transition and intertidal areas, salt marshes,
wetlands, and beaches. The coastal zone extends seaward to the outer
limit of the U.S. territorial

[[Page 55]]

sea and extends inland from the shorelines to the extent necessary to
control shorelands, the uses of which have a direct and significant
impact on the coastal waters, and the inward boundaries of which may be
identified by the several coastal States, under the authority in section
305(b)(1) of the Coastal Zone Management Act (CZMA) of 1972.
Competitive reservoir means a reservoir in which there are one or
more producible or producing well completions on each of two or more
leases or portions of leases, with different lease operating interests,
from which the lessees plan future production.
Containment dome means a non-pressurized container that can be used
to collect fluids escaping from the well or equipment below the sea
surface or from seeps by suspending the device over the discharge or
seep location. The containment dome includes all of the equipment
necessary to capture and convey fluids to the surface.
Correlative rights when used with respect to lessees of adjacent
leases, means the right of each lessee to be afforded an equal
opportunity to explore for, develop, and produce, without waste,
minerals from a common source.
Data means facts and statistics, measurements, or samples that have
not been analyzed, processed, or interpreted.
Departures mean approvals granted by the appropriate BSEE or BOEM
representative for operating requirements/procedures other than those
specified in the regulations found in this part. These requirements/
procedures may be necessary to control a well; properly develop a lease;
conserve natural resources, or protect life, property, or the marine,
coastal, or human environment.
Development means those activities that take place following
discovery of minerals in paying quantities, including but not limited to
geophysical activity, drilling, platform construction, and operation of
all directly related onshore support facilities, and which are for the
purpose of producing the minerals discovered.
Development geological and geophysical (G&G) activities mean those
G&G and related data-gathering activities on your lease or unit that you
conduct following discovery of oil, gas, or sulphur in paying quantities
to detect or imply the presence of oil, gas, or sulphur in commercial
quantities.
Director means the Director of BSEE of the U.S. Department of the
Interior, or an official authorized to act on the Director's behalf.
District Manager means the BSEE officer with authority and
responsibility for operations or other designated program functions for
a district within a BSEE Region. For activities on the Alaska OCS, any
reference in this part to District Manager means the BSEE Regional
Supervisor.
Easement means an authorization for a nonpossessory, nonexclusive
interest in a portion of the OCS, whether leased or unleased, which
specifies the rights of the holder to use the area embraced in the
easement in a manner consistent with the terms and conditions of the
granting authority.
Eastern Gulf of Mexico means all OCS areas of the Gulf of Mexico the
BOEM Director decides are adjacent to the State of Florida. The Eastern
Gulf of Mexico is not the same as the Eastern Planning Area, an area
established for OCS lease sales.
Emission offsets mean emission reductions obtained from facilities,
either onshore or offshore, other than the facility or facilities
covered by the proposed Exploration Plan (EP) or Development and
Production Plan (DPP).
Enhanced recovery operations mean pressure maintenance operations,
secondary and tertiary recovery, cycling, and similar recovery
operations that alter the natural forces in a reservoir to increase the
ultimate recovery of oil or gas.
Existing facility, as used in 30 CFR 550.303, means an OCS facility
described in an Exploration Plan or a Development and Production Plan
approved before June 2, 1980.
Exploration means the commercial search for oil, gas, or sulphur.
Activities classified as exploration include but are not limited to:
(1) Geophysical and geological (G&G) surveys using magnetic,
gravity, seismic reflection, seismic refraction, gas

[[Page 56]]

sniffers, coring, or other systems to detect or imply the presence of
oil, gas, or sulphur; and
(2) Any drilling conducted for the purpose of searching for
commercial quantities of oil, gas, and sulphur, including the drilling
of any additional well needed to delineate any reservoir to enable the
lessee to decide whether to proceed with development and production.
Facility means:
(1) As used in Sec. 250.130, all installations permanently or
temporarily attached to the seabed on the OCS (including manmade islands
and bottom-sitting structures). They include mobile offshore drilling
units (MODUs) or other vessels engaged in drilling or downhole
operations, used for oil, gas or sulphur drilling, production, or
related activities. They include all floating production systems (FPSs),
variously described as column-stabilized-units (CSUs); floating
production, storage and offloading facilities (FPSOs); tension-leg
platforms (TLPs); spars, etc. They also include facilities for product
measurement and royalty determination (e.g., lease Automatic Custody
Transfer Units, gas meters) of OCS production on installations not on
the OCS. Any group of OCS installations interconnected with walkways, or
any group of installations that includes a central or primary
installation with processing equipment and one or more satellite or
secondary installations is a single facility. The Regional Supervisor
may decide that the complexity of the individual installations justifies
their classification as separate facilities.
(2) As used in 30 CFR 550.303, means all installations or devices
permanently or temporarily attached to the seabed. They include mobile
offshore drilling units (MODUs), even while operating in the ``tender
assist'' mode (i.e., with skid-off drilling units) or other vessels
engaged in drilling or downhole operations. They are used for
exploration, development, and production activities for oil, gas, or
sulphur and emit or have the potential to emit any air pollutant from
one or more sources. They include all floating production systems
(FPSs), including column-stabilized-units (CSUs); floating production,
storage and offloading facilities (FPSOs); tension-leg platforms (TLPs);
spars, etc. During production, multiple installations or devices are a
single facility if the installations or devices are at a single site.
Any vessel used to transfer production from an offshore facility is part
of the facility while it is physically attached to the facility.
(3) As used in Sec. 250.490(b), means a vessel, a structure, or an
artificial island used for drilling, well completion, well-workover, or
production operations.
(4) As used in Sec. Sec. 250.900 through 250.921, means all
installations or devices permanently or temporarily attached to the
seabed. They are used for exploration, development, and production
activities for oil, gas, or sulphur and emit or have the potential to
emit any air pollutant from one or more sources. They include all
floating production systems (FPSs), including column-stabilized-units
(CSUs); floating production, storage and offloading facilities (FPSOs);
tension-leg platforms (TLPs); spars, etc. During production, multiple
installations or devices are a single facility if the installations or
devices are at a single site. Any vessel used to transfer production
from an offshore facility is part of the facility while it is physically
attached to the facility.
(5) As used in subpart S of this part, all types of structures
permanently or temporarily attached to the seabed (e.g., mobile offshore
drilling units (MODUs); floating production systems; floating
production, storage and offloading facilities; tension-leg platforms;
and spars) that are used for exploration, development, and production
activities for oil, gas, or sulphur in the OCS. Facilities also include
DOI-regulated pipelines.
Flaring means the burning of natural gas as it is released into the
atmosphere.
Gas reservoir means a reservoir that contains hydrocarbons
predominantly in a gaseous (single-phase) state.
Gas-well completion means a well completed in a gas reservoir or in
the associated gas-cap of an oil reservoir.
Geological and geophysical (G&G) explorations mean those G&G surveys
on

[[Page 57]]

your lease or unit that use seismic reflection, seismic refraction,
magnetic, gravity, gas sniffers, coring, or other systems to detect or
imply the presence of oil, gas, or sulphur in commercial quantities.
Governor means the Governor of a State, or the person or entity
designated by, or under, State law to exercise the powers granted to
such Governor under the Act.
H2S absent means:
(1) Drilling, logging, coring, testing, or producing operations have
confirmed the absence of H2S in concentrations that could
potentially result in atmospheric concentrations of 20 ppm or more of
H2S; or
(2) Drilling in the surrounding areas and correlation of geological
and seismic data with equivalent stratigraphic units have confirmed an
absence of H2S throughout the area to be drilled.
H2S present means drilling, logging, coring, testing, or producing
operations have confirmed the presence of H2S in
concentrations and volumes that could potentially result in atmospheric
concentrations of 20 ppm or more of H2S.
H2S unknown means the designation of a zone or geologic formation
where neither the presence nor absence of H2S has been
confirmed.
Human environment means the physical, social, and economic
components, conditions, and factors that interactively determine the
state, condition, and quality of living conditions, employment, and
health of those affected, directly or indirectly, by activities
occurring on the OCS.
Interpreted geological information means geological knowledge, often
in the form of schematic cross sections, 3-dimensional representations,
and maps, developed by determining the geological significance of data
and analyzed geological information.
Interpreted geophysical information means geophysical knowledge,
often in the form of schematic cross sections, 3-dimensional
representations, and maps, developed by determining the geological
significance of geophysical data and analyzed geophysical information.
Lease means an agreement that is issued under section 8 or
maintained under section 6 of the Act and that authorizes exploration
for, and development and production of, minerals. The term also means
the area covered by that authorization, whichever the context requires.
Lease term pipelines mean those pipelines owned and operated by a
lessee or operator that are completely contained within the boundaries
of a single lease, unit, or contiguous (not cornering) leases of that
lessee or operator.
Lessee means a person who has entered into a lease with the United
States to explore for, develop, and produce the leased minerals. The
term lessee also includes the BOEM-approved assignee of the lease, and
the owner or the BOEM-approved assignee of operating rights for the
lease.
Major Federal action means any action or proposal by the Secretary
that is subject to the provisions of section 102(2)(C) of the National
Environmental Policy Act of 1969, 42 U.S.C. (2)(C) (i.e., an action that
will have a significant impact on the quality of the human environment
requiring preparation of an environmental impact statement under section
102(2)(C) of the National Environmental Policy Act).
Marine environment means the physical, atmospheric, and biological
components, conditions, and factors that interactively determine the
productivity, state, condition, and quality of the marine ecosystem.
These include the waters of the high seas, the contiguous zone,
transitional and intertidal areas, salt marshes, and wetlands within the
coastal zone and on the OCS.
Material remains mean physical evidence of human habitation,
occupation, use, or activity, including the site, location, or context
in which such evidence is situated.
Maximum efficient rate (MER) means the maximum sustainable daily oil
or gas withdrawal rate from a reservoir that will permit economic
development and depletion of that reservoir without detriment to
ultimate recovery.
Maximum production rate (MPR) means the approved maximum daily rate
at which oil or gas may be produced from a specified oil-well or gas-
well completion.
Minerals include oil, gas, sulphur, geopressured-geothermal and
associated resources, and all other minerals

[[Page 58]]

that are authorized by an Act of Congress to be produced.
Natural resources include, without limiting the generality thereof,
oil, gas, and all other minerals, and fish, shrimp, oysters, clams,
crabs, lobsters, sponges, kelp, and other marine animal and plant life
but does not include water power or the use of water for the production
of power.
Nonattainment area means, for any air pollutant, an area that is
shown by monitored data or that is calculated by air quality modeling
(or other methods determined by the Administrator of EPA to be reliable)
to exceed any primary or secondary ambient air quality standard
established by EPA.
Nonsensitive reservoir means a reservoir in which ultimate recovery
is not decreased by high reservoir production rates.
Oil reservoir means a reservoir that contains hydrocarbons
predominantly in a liquid (single-phase) state.
Oil reservoir with an associated gas cap means a reservoir that
contains hydrocarbons in both a liquid and gaseous (two-phase) state.
Oil-well completion means a well completed in an oil reservoir or in
the oil accumulation of an oil reservoir with an associated gas cap.
Operating rights mean any interest held in a lease with the right to
explore for, develop, and produce leased substances.
Operator means the person the lessee(s) designates as having control
or management of operations on the leased area or a portion thereof. An
operator may be a lessee, the BSEE-approved or BOEM-approved designated
agent of the lessee(s), or the holder of operating rights under a BOEM-
approved operating rights assignment.
Outer Continental Shelf (OCS) means all submerged lands lying
seaward and outside of the area of lands beneath navigable waters as
defined in section 2 of the Submerged Lands Act (43 U.S.C. 1301) whose
subsoil and seabed appertain to the United States and are subject to its
jurisdiction and control.
Person includes a natural person, an association (including
partnerships, joint ventures, and trusts), a State, a political
subdivision of a State, or a private, public, or municipal corporation.
Pipelines are the piping, risers, and appurtenances installed for
transporting oil, gas, sulphur, and produced waters.
Processed geological or geophysical information means data collected
under a permit or a lease that have been processed or reprocessed.
Processing involves changing the form of data to facilitate
interpretation. Processing operations may include, but are not limited
to, applying corrections for known perturbing causes, rearranging or
filtering data, and combining or transforming data elements.
Reprocessing is the additional processing other than ordinary processing
used in the general course of evaluation. Reprocessing operations may
include varying identified parameters for the detailed study of a
specific problem area.
Production means those activities that take place after the
successful completion of any means for the removal of minerals,
including such removal, field operations, transfer of minerals to shore,
operation monitoring, maintenance, and workover operations.
Production areas are those areas where flammable petroleum gas,
volatile liquids or sulphur are produced, processed (e.g., compressed),
stored, transferred (e.g., pumped), or otherwise handled before entering
the transportation process.
Projected emissions mean emissions, either controlled or
uncontrolled, from a source or sources.
Prospect means a geologic feature having the potential for mineral
deposits.
Regional Director means the BSEE officer with responsibility and
authority for a Region within BSEE.
Regional Supervisor means the BSEE officer with responsibility and
authority for operations or other designated program functions within a
BSEE Region.
Right-of-use means any authorization issued under 30 CFR Part 550 to
use OCS lands.
Right-of-way pipelines are those pipelines that are contained
within:
(1) The boundaries of a single lease or unit, but are not owned and
operated

[[Page 59]]

by a lessee or operator of that lease or unit;
(2) The boundaries of contiguous (not cornering) leases that do not
have a common lessee or operator;
(3) The boundaries of contiguous (not cornering) leases that have a
common lessee or operator but are not owned and operated by that common
lessee or operator; or
(4) An unleased block(s).
Routine operations, for the purposes of subpart F, mean any of the
following operations conducted on a well with the tree installed:
(1) Cutting paraffin;
(2) Removing and setting pump-through-type tubing plugs, gas-lift
valves, and subsurface safety valves that can be removed by wireline
operations;
(3) Bailing sand;
(4) Pressure surveys;
(5) Swabbing;
(6) Scale or corrosion treatment;
(7) Caliper and gauge surveys;
(8) Corrosion inhibitor treatment;
(9) Removing or replacing subsurface pumps;
(10) Through-tubing logging (diagnostics);
(11) Wireline fishing;
(12) Setting and retrieving other subsurface flow-control devices;
and
(13) Acid treatments.
Sensitive reservoir means a reservoir in which the production rate
will affect ultimate recovery.
Significant archaeological resource means those archaeological
resources that meet the criteria of significance for eligibility to the
National Register of Historic Places as defined in 36 CFR 60.4, or its
successor.
Source control and containment equipment (SCCE) means the capping
stack, cap and flow system, containment dome, and/or other subsea and
surface devices, equipment, and vessels the collective purpose of which
is to control a spill source and stop the flow of fluids into the
environment or to contain fluids escaping into the environment.
``Surface devices'' refers to equipment mounted or staged on a barge,
vessel, or facility to separate, treat, store and/or dispose of fluids
conveyed to the surface by the cap and flow system or the containment
dome. ``Subsea devices'' includes, but is not limited to, remotely
operated vehicles, anchors, buoyancy equipment, connectors, cameras,
controls and other subsea equipment necessary to facilitate the
deployment, operation, and retrieval of the SCCE. The SCCE does not
include a blowout preventer.
Suspension means a granted or directed deferral of the requirement
to produce (Suspension of Production (SOP)) or to conduct leaseholding
operations (Suspension of Operations (SOO)).
Venting means the release of gas into the atmosphere without
igniting it. This includes gas that is released underwater and bubbles
to the atmosphere.
Waste of oil, gas, or sulphur means:
(1) The physical waste of oil, gas, or sulphur;
(2) The inefficient, excessive, or improper use, or the unnecessary
dissipation of reservoir energy;
(3) The locating, spacing, drilling, equipping, operating, or
producing of any oil, gas, or sulphur well(s) in a manner that causes or
tends to cause a reduction in the quantity of oil, gas, or sulphur
ultimately recoverable under prudent and proper operations or that
causes or tends to cause unnecessary or excessive surface loss or
destruction of oil or gas; or
(4) The inefficient storage of oil.
Welding means all activities connected with welding, including hot
tapping and burning.
Wellbay is the area on a facility within the perimeter of the
outermost wellheads.
Well-completion operations mean the work conducted to establish
production from a well after the production-casing string has been set,
cemented, and pressure-tested.
Well-control fluid means drilling mud, completion fluid, or workover
fluid as appropriate to the particular operation being conducted.
Western Gulf of Mexico means all OCS areas of the Gulf of Mexico
except those the BOEM Director decides are adjacent to the State of
Florida. The Western Gulf of Mexico is not the same as the Western
Planning Area, an area established for OCS lease sales.

[[Page 60]]

Workover operations mean the work conducted on wells after the
initial well-completion operation for the purpose of maintaining or
restoring the productivity of a well.
You means a lessee, the owner or holder of operating rights, a
designated operator or agent of the lessee(s), a pipeline right-of-way
holder, or a State lessee granted a right-of-use and easement.

[76 FR 64462, Oct. 18, 2011, as amended at 78 FR 20439, Apr. 5, 2013; 81
FR 46560, July 15, 2016]

Performance Standards

Sec. 250.106 What standards will the Director use to regulate
lease operations?

The Director will regulate all operations under a lease, right-of-
use and easement, or right-of-way to:
(a) Promote orderly exploration, development, and production of
mineral resources;
(b) Prevent injury or loss of life;
(c) Prevent damage to or waste of any natural resource, property, or
the environment; and
(d) Cooperate and consult with affected States, local governments,
other interested parties, and relevant Federal agencies.

Sec. 250.107 What must I do to protect health, safety, property,
and the environment?

(a) You must protect health, safety, property, and the environment
by:
(1) Performing all operations in a safe and workmanlike manner;
(2) Maintaining all equipment and work areas in a safe condition;
(3) Utilizing recognized engineering practices that reduce risks to
the lowest level practicable when conducting design, fabrication,
installation, operation, inspection, repair, and maintenance activities;
and
(4) Complying with all lease, plan, and permit terms and conditions.
(b) You must immediately control, remove, or otherwise correct any
hazardous oil and gas accumulation or other health, safety, or fire
hazard.
(c) Best available and safest technology. (1) On all new drilling
and production operations and, except as provided in paragraph (c)(3) of
this section, on existing operations, you must use the best available
and safest technologies (BAST) which the Director determines to be
economically feasible whenever the Director determines that failure of
equipment would have a significant effect on safety, health, or the
environment, except where the Director determines that the incremental
benefits are clearly insufficient to justify the incremental costs of
utilizing such technologies.
(2) Conformance with BSEE regulations will be presumed to constitute
the use of BAST unless and until the Director determines that other
technologies are required pursuant to paragraph (c)(1) of this section.
(3) The Director may waive the requirement to use BAST on a category
of existing operations if the Director determines that use of BAST by
that category of existing operations would not be practicable. The
Director may waive the requirement to use BAST on an existing operation
at a specific facility if you submit a waiver request demonstrating that
the use of BAST would not be practicable.
(d) BSEE may issue orders to ensure compliance with this part,
including, but not limited to, orders to produce and submit records and
to inspect, repair, and/or replace equipment. BSEE may also issue orders
to shut-in operations of a component or facility because of a threat of
serious, irreparable, or immediate harm to health, safety, property, or
the environment posed by those operations or because the operations
violate law, including a regulation, order, or provision of a lease,
plan, or permit.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 26014, Apr. 29, 2016;
81 FR 61915, Sept. 7, 2016]

Sec. 250.108 What requirements must I follow for cranes and other
material-handling equipment?

(a) All cranes installed on fixed platforms must be operated in
accordance with American Petroleum Institute's Recommended Practice for
Operation and Maintenance of Offshore Cranes, API RP 2D (as incorporated
by reference in Sec. 250.198).

[[Page 61]]

(b) All cranes installed on fixed platforms must be equipped with a
functional anti-two block device.
(c) If a fixed platform is installed after March 17, 2003, all
cranes on the platform must meet the requirements of American Petroleum
Institute Specification for Offshore Pedestal Mounted Cranes, API Spec
2C (as incorporated by reference in Sec. 250.198).
(d) All cranes manufactured after March 17, 2003, and installed on a
fixed platform, must meet the requirements of API Spec 2C.
(e) You must maintain records specific to a crane or the operation
of a crane installed on an OCS fixed platform, as follows:
(1) Retain all design and construction records, including
installation records for any anti-two block safety devices, for the life
of the crane. The records must be kept at the OCS fixed platform.
(2) Retain all inspection, testing, and maintenance records of
cranes for at least 4 years. The records must be kept at the OCS fixed
platform.
(3) Retain the qualification records of the crane operator and all
rigger personnel for at least 4 years. The records must be kept at the
OCS fixed platform.
(f) You must operate and maintain all other material-handling
equipment in a manner that ensures safe operations and prevents
pollution.

Sec. 250.109 What documents must I prepare and maintain related to welding?

(a) You must submit a Welding Plan to the District Manager before
you begin drilling or production activities on a lease. You may not
begin welding until the District Manager has approved your plan.
(b) You must keep the following at the site where welding occurs:
(1) A copy of the plan and its approval letter; and
(2) Drawings showing the designated safe-welding areas.

Sec. 250.110 What must I include in my welding plan?

You must include all of the following in the welding plan that you
prepare under Sec. 250.109:
(a) Standards or requirements for welders;
(b) How you will ensure that only qualified personnel weld;
(c) Practices and procedures for safe welding that address:
(1) Welding in designated safe areas;
(2) Welding in undesignated areas, including wellbay;
(3) Fire watches;
(4) Maintenance of welding equipment; and
(5) Plans showing all designated safe-welding areas.
(d) How you will prevent spark-producing activities (i.e., grinding,
abrasive blasting/cutting and arc-welding) in hazardous locations.

Sec. 250.111 Who oversees operations under my welding plan?

A welding supervisor or a designated person in charge must be
thoroughly familiar with your welding plan. This person must ensure that
each welder is properly qualified according to the welding plan. This
person also must inspect all welding equipment before welding.

Sec. 250.112 What standards must my welding equipment meet?

Your welding equipment must meet the following requirements:
(a) All engine-driven welding equipment must be equipped with spark
arrestors and drip pans;
(b) Welding leads must be completely insulated and in good
condition;
(c) Hoses must be leak-free and equipped with proper fittings,
gauges, and regulators; and
(d) Oxygen and fuel gas bottles must be secured in a safe place.

Sec. 250.113 What procedures must I follow when welding?

(a) Before you weld, you must move any equipment containing
hydrocarbons or other flammable substances at least 35 feet horizontally
from the welding area. You must move similar equipment on lower decks at
least 35 feet from the point of impact where slag, sparks, or other
burning materials could fall. If moving this equipment is impractical,
you must protect that equipment with flame-proofed

[[Page 62]]

covers, shield it with metal or fire-resistant guards or curtains, or
render the flammable substances inert.
(b) While you weld, you must monitor all water-discharge-point
sources from hydrocarbon-handling vessels. If a discharge of flammable
fluids occurs, you must stop welding.
(c) If you cannot weld in one of the designated safe-welding areas
that you listed in your safe welding plan, you must meet the following
requirements:
(1) You may not begin welding until:
(i) The welding supervisor or designated person in charge advises in
writing that it is safe to weld.
(ii) You and the designated person in charge inspect the work area
and areas below it for potential fire and explosion hazards.
(2) During welding, the person in charge must designate one or more
persons as a fire watch. The fire watch must:
(i) Have no other duties while actual welding is in progress;
(ii) Have usable firefighting equipment;
(iii) Remain on duty for 30 minutes after welding activities end;
and
(iv) Maintain a continuous surveillance with a portable gas detector
during the welding and burning operation if welding occurs in an area
not equipped with a gas detector.
(3) You may not weld piping, containers, tanks, or other vessels
that have contained a flammable substance unless you have rendered the
contents inert and the designated person in charge has determined it is
safe to weld. This does not apply to approved hot taps.
(4) You may not weld within 10 feet of a wellbay unless you have
shut in all producing wells in that wellbay.
(5) You may not weld within 10 feet of a production area, unless you
have shut in that production area.
(6) You may not weld while you drill, complete, workover, or conduct
wireline operations unless:
(i) The fluids in the well (being drilled, completed, worked over,
or having wireline operations conducted) are noncombustible; and
(ii) You have precluded the entry of formation hydrocarbons into the
wellbore by either mechanical means or a positive overbalance toward the
formation.

Sec. 250.114 How must I install, maintain, and operate electrical equipment?

The requirements in this section apply to all electrical equipment
on all platforms, artificial islands, fixed structures, and their
facilities.
(a) You must classify all areas according to API RP 500, Recommended
Practice for Classification of Locations for Electrical Installations at
Petroleum Facilities Classified as Class I, Division 1 and Division 2
(as incorporated by reference in Sec. 250.198), or API RP 505,
Recommended Practice for Classification of Locations for Electrical
Installations at Petroleum Facilities Classified as Class I, Zone 0,
Zone 1, and Zone 2 (as incorporated by reference in Sec. 250.198).
(b) Employees who maintain your electrical systems must have
expertise in area classification and the performance, operation and
hazards of electrical equipment.
(c) You must install all electrical systems according to API RP 14F,
Recommended Practice for Design and Installation of Electrical Systems
for Fixed and Floating Offshore Petroleum Facilities for Unclassified
and Class I, Division 1, and Division 2 Locations (as incorporated by
reference in Sec. 250.198), or API RP 14FZ, Recommended Practice for
Design and Installation of Electrical Systems for Fixed and Floating
Offshore Petroleum Facilities for Unclassified and Class I, Zone 0, Zone
1, and Zone 2 Locations (as incorporated by reference in Sec. 250.198).
(d) On each engine that has an electric ignition system, you must
use an ignition system designed and maintained to reduce the release of
electrical energy.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36149, June 6, 2016]

Sec. Sec. 250.115-250.117 [Reserved]

Gas Storage or Injection

Sec. 250.118 Will BSEE approve gas injection?

The Regional Supervisor may authorize you to inject gas on the OCS,
on and off-lease, to promote conservation

[[Page 63]]

of natural resources and to prevent waste.
(a) To receive BSEE approval for injection, you must:
(1) Show that the injection will not result in undue interference
with operations under existing leases; and
(2) Submit a written application to the Regional Supervisor for
injection of gas.
(b) The Regional Supervisor will approve gas injection applications
that:
(1) Enhance recovery;
(2) Prevent flaring of casinghead gas; or
(3) Implement other conservation measures approved by the Regional
Supervisor.

Sec. 250.119 [Reserved]

Sec. 250.120 How does injecting, storing, or treating gas affect
my royalty payments?

(a) If you produce gas from an OCS lease and inject it into a
reservoir on the lease or unit for the purposes cited in Sec.
250.118(b), you are not required to pay royalties until you remove or
sell the gas from the reservoir.
(b) If you produce gas from an OCS lease and store it according to
30 CFR 550.119, you must pay royalty before injecting it into the
storage reservoir.
(c) If you produce gas from an OCS lease and treat it at an off-
lease or off-unit location, you must pay royalties when the gas is first
produced.

Sec. 250.121 What happens when the reservoir contains both original gas
in place and injected gas?

If the reservoir contains both original gas in place and injected
gas, when you produce gas from the reservoir you must use a BSEE-
approved formula to determine the amounts of injected or stored gas and
gas original to the reservoir.

Sec. 250.122 What effect does subsurface storage have on the lease term?

If you use a lease area for subsurface storage of gas, it does not
affect the continuance or expiration of the lease.

Sec. 250.123 [Reserved]

Sec. 250.124 Will BSEE approve gas injection into the cap rock containing
a sulphur deposit?

To receive the Regional Supervisor's approval to inject gas into the
cap rock of a salt dome containing a sulphur deposit, you must show that
the injection:
(a) Is necessary to recover oil and gas contained in the cap rock;
and
(b) Will not significantly increase potential hazards to present or
future sulphur mining operations.

Fees

Sec. 250.125 Service fees.

(a) The table in this paragraph (a) shows the fees that you must pay
to BSEE for the services listed. The fees will be adjusted periodically
according to the Implicit Price Deflator for Gross Domestic Product by
publication of a document in the Federal Register. If a significant
adjustment is needed to arrive at the new actual cost for any reason
other than inflation, then a proposed rule containing the new fees will
be published in the Federal Register for comment.

------------------------------------------------------------------------
Service--processing of the
following: Fee amount 30 CFR citation
------------------------------------------------------------------------
(1) Suspension of Operations/ $2,123................ Sec.
Suspension of Production (SOO/ 250.171(e).
SOP) Request.
(2) Deepwater Operations Plan $3,599................ Sec.
(DWOP). 250.292(q).
(3) Application for Permit to $2,113 for initial Sec.
Drill (APD); Form BSEE-0123. applications only; no 250.410(d);
fee for revisions. Sec.
250.513(b);
Sec.
250.1617(a).
(4) Application for Permit to $125.................. Sec.
Modify (APM); Form BSEE-0124. 250.465(b);
Sec.
250.513(b);
Sec.
250.613(b);
Sec.
250.1618(a);
Sec.
250.1704(g).

[[Page 64]]

(5) New Facility Production $5,426................ Sec. 250.842.
Safety System Application for $14,280 additional fee
facility with more than 125 will be charged if
components. BSEE conducts a pre-
production inspection
of a facility
offshore, and $7,426
for an inspection of
a facility while in a
shipyard.
A component is a piece
of equipment or
ancillary system that
is protected by one
or more of the safety
devices required by
API RP 14C (as
incorporated by
reference in Sec.
250.198).
(6) New Facility Production $1,314................ Sec. 250.842.
Safety System Application for $8,967 additional fee
facility with 25-125 will be charged if
components. BSEE conducts a pre-
production inspection
of a facility
offshore, and $5,141
for an inspection of
a facility while in a
shipyard.
(7) New Facility Production $652.................. Sec. 250.842.
Safety System Application for
facility with fewer than 25
components.
(8) Production Safety System $605.................. Sec. 250.842.
Application--Modification
with more than 125 components
reviewed.
(9) Production Safety System $217.................. Sec. 250.842.
Application--Modification
with 25-125 components
reviewed.
(10) Production Safety System $92................... Sec. 250.842.
Application--Modification
with fewer than 25 components
reviewed.
(11) Platform Application-- $22,734............... Sec.
Installation--Under the 250.905(l).
Platform Verification Program.
(12) Platform Application-- $3,256................ Sec.
Installation--Fixed Structure 250.905(l).
Under the Platform Approval
Program.
(13) Platform Application-- $1,657................ Sec.
Installation--Caisson/Well 250.905(l)
Protector.
(14) Platform Application-- $3,884................ Sec.
Modification/Repair. 250.905(l).
(15) New Pipeline Application $3,541................ Sec.
(Lease Term). 250.1000(b).
(16) Pipeline Application-- $2,056................ Sec.
Modification (Lease Term). 250.1000(b).
(17) Pipeline Application-- $4,169................ Sec.
Modification (ROW). 250.1000(b).
(18) Pipeline Repair $388.................. Sec.
Notification. 250.1008(e).
(19) Pipeline Right-of-Way $2,771................ Sec.
(ROW) Grant Application. 250.1015(a).
(20) Pipeline Conversion of $236.................. Sec.
Lease Term to ROW. 250.1015(a).
(21) Pipeline ROW Assignment.. $201.................. Sec.
250.1018(b).
(22) 500 Feet From Lease/Unit $3,892................ Sec.
Line Production Request. 250.1156(a).
(23) Gas Cap Production $4,953................ Sec. 250.1157.
Request.
(24) Downhole Commingling $5,779................ Sec.
Request. 250.1158(a).
(25) Complex Surface $4,056................ Sec.
Commingling and Measurement 250.1202(a);
Application. Sec.
250.1203(b);
Sec.
250.1204(a).
(26) Simple Surface $1,371................ Sec.
Commingling and Measurement 250.1202(a);
Application. Sec.
250.1203(b);
Sec.
250.1204(a).
(27) Voluntary Unitization $12,619............... Sec.
Proposal or Unit Expansion. 250.1303(d).
(28) Unitization Revision..... $896.................. Sec.
250.1303(d).
(29) Application to Remove a $4,684................ Sec. 250.1727.
Platform or Other Facility.
(30) Application to $1,142................ Sec.
Decommission a Pipeline 250.1751(a) or
(Lease Term). Sec.
250.1752(a).

[[Page 65]]

(31) Application to $2,170................ Sec.
Decommission a Pipeline (ROW). 250.1751(a) or
Sec.
250.1752(a).
------------------------------------------------------------------------

(b) Payment of the fees listed in paragraph (a) of this section must
accompany the submission of the document for approval or be sent to an
office identified by the Regional Director. Once a fee is paid, it is
nonrefundable, even if an application or other request is withdrawn. If
your application is returned to you as incomplete, you are not required
to submit a new fee when you submit the amended application.
(c) Verbal approvals are occasionally given in special
circumstances. Any action that will be considered a verbal permit
approval requires either a paper permit application to follow the verbal
approval or an electronic application submittal within 72 hours. Payment
must be made with the completed paper or electronic application.

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50891, Aug. 22, 2012;
78 FR 60213, Oct. 1, 2013; 81 FR 26014, Apr. 29, 2016; 81 FR 61916,
Sept. 7, 2016]

Sec. 250.126 Electronic payment instructions.

(a) You must file all payments electronically through the Fees for
Services page on the BSEE Web site at http://www.bsee.gov. This
includes, but is not limited to, all OCS applications, permits, or any
filing fees. You must include a copy of the Pay.gov confirmation receipt
page with your application, permit, or filing fee.
(b) If you submitted an application or permit through eWell, you
must use the interactive payment feature in that system, which directs
you through Pay.gov to make a payment. It is recommended that you keep a
copy of your payment confirmation receipt in the event that any
questions arise regarding your transaction.

[81 FR 36149, June 6, 2016]

Inspections of Operations

Sec. 250.130 Why does BSEE conduct inspections?

BSEE will inspect OCS facilities and any vessels engaged in drilling
or other downhole operations. These include facilities under
jurisdiction of other Federal agencies that we inspect by agreement. We
conduct these inspections:
(a) To verify that you are conducting operations according to the
Act, the regulations, the lease, right-of-way, the BOEM-approved
Exploration Plan or Development and Production Plans; or right-of-use
and easement, and other applicable laws and regulations; and
(b) To determine whether equipment designed to prevent or ameliorate
blowouts, fires, spillages, or other major accidents has been installed
and is operating properly according to the requirements of this part.

Sec. 250.131 Will BSEE notify me before conducting an inspection?

BSEE conducts both scheduled and unscheduled inspections.

Sec. 250.132 What must I do when BSEE conducts an inspection?

(a) When BSEE conducts an inspection, you must provide:
(1) Access to all platforms, artificial islands, and other
installations on your leases or associated with your lease, right-of-use
and easement, or right-of-way; and
(2) Helicopter landing sites and refueling facilities for any
helicopters we use to regulate offshore operations.
(b) You must make the following available for us to inspect:
(1) The area covered under a lease, right-of-use and easement,
right-of-way, or permit;
(2) All improvements, structures, and fixtures on these areas; and
(3) All records of design, construction, operation, maintenance,
repairs, or investigations on or related to the area.

[[Page 66]]

Sec. 250.133 Will BSEE reimburse me for my expenses related to inspections?

Upon request, BSEE will reimburse you for food, quarters, and
transportation that you provide for BSEE representatives while they
inspect lease facilities and operations. You must send us your
reimbursement request within 90 days of the inspection.

Disqualification

Sec. 250.135 What will BSEE do if my operating performance is unacceptable?

BSEE will determine if your operating performance is unacceptable.
BSEE will refer a determination of unacceptable performance to BOEM, who
may disapprove or revoke your designation as operator on a single
facility or multiple facilities. We will give you adequate notice and
opportunity for a review by BSEE officials before making a determination
that your operating performance is unacceptable.

Sec. 250.136 How will BSEE determine if my operating performance
is unacceptable?

In determining if your operating performance is unacceptable, BSEE
will consider, individually or collectively:
(a) Accidents and their nature;
(b) Pollution events, environmental damages and their nature;
(c) Incidents of noncompliance;
(d) Civil penalties;
(e) Failure to adhere to OCS lease obligations; or
(f) Any other relevant factors.

Special Types of Approvals

Sec. 250.140 When will I receive an oral approval?

When you apply for BSEE approval of any activity, we normally give
you a written decision. The following table shows circumstances under
which we may give an oral approval.

------------------------------------------------------------------------
When you . . . We may . . . And . . .
------------------------------------------------------------------------
(a) Request approval Give you an oral You must then confirm the
orally approval, oral request by sending
us a written request
within 72 hours.
(b) Request approval Give you an oral We will send you a
in writing, approval if quick written approval
action is needed, afterward. It will
include any conditions
that we place on the
oral approval.
(c) Request approval Give you an oral You don't have to follow
orally for gas approval, up with a written
flaring, request unless the
Regional Supervisor
requires it. When you
stop the approved
flaring, you must
promptly send a letter
summarizing the
location, dates and
hours, and volumes of
liquid hydrocarbons
produced and gas flared
by the approved flaring
(see 30 CFR 250, subpart
K).
------------------------------------------------------------------------

Sec. 250.141 May I ever use alternate procedures or equipment?

You may use alternate procedures or equipment after receiving
approval as described in this section.
(a) Any alternate procedures or equipment that you propose to use
must provide a level of safety and environmental protection that equals
or surpasses current BSEE requirements.
(b) You must receive the District Manager's or Regional Supervisor's
written approval before you can use alternate procedures or equipment.
(c) To receive approval, you must either submit information or give
an oral presentation to the appropriate Regional Supervisor. Your
presentation must describe the site-specific application(s), performance
characteristics, and safety features of the proposed procedure or
equipment.

Sec. 250.142 How do I receive approval for departures?

We may approve departures to the operating requirements. You may
apply for a departure by writing to the District Manager or Regional
Supervisor.

Sec. Sec. 250.143-250.144 [Reserved]

Sec. 250.145 How do I designate an agent or a local agent?

(a) You or your designated operator may designate for the Regional
Supervisor's approval, or the Regional Director may require you to
designate an

[[Page 67]]

agent empowered to fulfill your obligations under the Act, the lease, or
the regulations in this part.
(b) You or your designated operator may designate for the Regional
Supervisor's approval a local agent empowered to receive notices and
submit requests, applications, notices, or supplemental information.

Sec. 250.146 Who is responsible for fulfilling leasehold obligations?

(a) When you are not the sole lessee, you and your co-lessee(s) are
jointly and severally responsible for fulfilling your obligations under
the provisions of 30 CFR parts 250 through 282 and 30 CFR parts 550
through 582 unless otherwise provided in these regulations.
(b) If your designated operator fails to fulfill any of your
obligations under 30 CFR parts 250 through 282 and 30 CFR parts 550
through 582, the Regional Supervisor may require you or any or all of
your co-lessees to fulfill those obligations or other operational
obligations under the Act, the lease, or the regulations.
(c) Whenever the regulations in 30 CFR parts 250 through 282 and 30
CFR parts 550 through 582 require the lessee to meet a requirement or
perform an action, the lessee, operator (if one has been designated),
and the person actually performing the activity to which the requirement
applies are jointly and severally responsible for complying with the
regulation.

Naming and Identifying Facilities and Wells (Does Not Include MODUs)

Sec. 250.150 How do I name facilities and wells in the Gulf of Mexico Region?

(a) Assign each facility a letter designation except for those types
of facilities identified in paragraph (c)(1) of this section. For
example, A, B, CA, or CB.
(1) After a facility is installed, rename each predrilled well that
was assigned only a number and was suspended temporarily at the mudline
or at the surface. Use a letter and number designation. The letter used
must be the same as that of the production facility, and the number used
must correspond to the order in which the well was completed, not
necessarily the number assigned when it was drilled. For example, the
first well completed for production on Facility A would be renamed Well
A-1, the second would be Well A-2, and so on; and
(2) When you have more than one facility on a block, each facility
installed, and not bridge-connected to another facility, must be named
using a different letter in sequential order. For example, EC 222A, EC
222B, EC 222C.
(3) When you have more than one facility on multiple blocks in a
local area being co-developed, each facility installed and not connected
with a walkway to another facility should be named using a different
letter in sequential order with the block number corresponding to the
block on which the platform is located. For example, EC 221A, EC 222B,
and EC 223C.
(b) In naming multiple well caissons, you must assign a letter
designation.
(c) In naming single well caissons, you must use certain criteria as
follows:
(1) For single well caissons not attached to a facility with a
walkway, use the well designation. For example, Well No. 1;
(2) For single well caissons attached to a facility with a walkway,
use the same designation as the facility. For example, rename Well No.10
as A-10; and
(3) For single well caissons with production equipment, use a letter
designation for the facility name and a letter plus number designation
for the well. For example, the Well No. 1 caisson would be designated as
Facility A, and the well would be Well A-1.

Sec. 250.151 How do I name facilities in the Pacific Region?

The operator assigns a name to the facility.

Sec. 250.152 How do I name facilities in the Alaska Region?

Facilities will be named and identified according to the Regional
Director's directions.

[[Page 68]]

Sec. 250.153 Do I have to rename an existing facility or well?

You do not have to rename facilities installed and wells drilled
before January 27, 2000, unless the Regional Director requires it.

Sec. 250.154 What identification signs must I display?

(a) You must identify all facilities, artificial islands, and mobile
offshore drilling units with a sign maintained in a legible condition.
(1) You must display an identification sign that can be viewed from
the waterline on at least one side of the platform. The sign must use at
least 3-inch letters and figures.
(2) When helicopter landing facilities are present, you must display
an additional identification sign that is visible from the air. The sign
must use at least 12-inch letters and figures and must also display the
weight capacity of the helipad unless noted on the top of the helipad.
If this sign is visible to both helicopter and boat traffic, then the
sign in paragraph (a)(1) of this section is not required.
(3) Your identification sign must:
(i) List the name of the lessee or designated operator;
(ii) In the GOM OCS Region, list the area designation or
abbreviation and the block number of the facility location as depicted
on OCS Official Protraction Diagrams or leasing maps;
(iii) In the Pacific OCS Region, list the lease number on which the
facility is located; and
(iv) List the name of the platform, structure, artificial island, or
mobile offshore drilling unit.
(b) You must identify singly completed wells and multiple
completions as follows:
(1) For each singly completed well, list the lease number and well
number on the wellhead or on a sign affixed to the wellhead;
(2) For wells with multiple completions, downhole splitter wells,
and multilateral wells, identify each completion in addition to the well
name and lease number individually on the well flowline at the wellhead;
and
(3) For subsea wells that flow individually into separate pipelines,
affix the required sign on the pipeline or surface flowline dedicated to
that subsea well at a convenient location on the receiving platform. For
multiple subsea wells that flow into a common pipeline or pipelines, no
sign is required.

Sec. Sec. 250.160-250.167 [Reserved]

Suspensions

Sec. 250.168 May operations or production be suspended?

(a) You may request approval of a suspension, or the Regional
Supervisor may direct a suspension (Directed Suspension), for all or any
part of a lease or unit area.
(b) Depending on the nature of the suspended activity, suspensions
are labeled either Suspensions of Operations (SOO) or Suspensions of
Production (SOP).

Sec. 250.169 What effect does suspension have on my lease?

(a) A suspension may extend the term of a lease (see Sec.
250.180(b), (d), and (e)). The extension is equal to the length of time
the suspension is in effect, except as provided in paragraph (b) of this
section.
(b) A Directed Suspension does not extend the term of a lease when
the Regional Supervisor directs a suspension because of:
(1) Gross negligence; or
(2) A willful violation of a provision of the lease or governing
statutes and regulations.

Sec. 250.170 How long does a suspension last?

(a) BSEE may issue suspensions for up to 5 years per suspension. The
Regional Supervisor will set the length of the suspension based on the
conditions of the individual case involved. BSEE may grant consecutive
suspension periods.
(b) An SOO ends automatically when the suspended operation
commences.
(c) An SOP ends automatically when production begins.
(d) A Directed Suspension normally ends as specified in the letter
directing the suspension.
(e) BSEE may terminate any suspension when the Regional Supervisor
determines the circumstances that justified the suspension no longer
exist or

[[Page 69]]

that other lease conditions warrant termination. The Regional Supervisor
will notify you of the reasons for termination and the effective date.

Sec. 250.171 How do I request a suspension?

You must submit your request for a suspension to the Regional
Supervisor, and BSEE must receive the request before the end of the
lease term (i.e., end of primary term, end of the 1-year period
following the last leaseholding operation, and end of a current
suspension). Your request must include:
(a) The justification for the suspension including the length of
suspension requested;
(b) A reasonable schedule of work leading to the commencement or
restoration of the suspended activity;
(c) A statement that a well has been drilled on the lease and
determined to be producible according to Sec. 250.1603 (SOP only), 30
CFR 550.115, or 30 CFR 550.116;
(d) A commitment to production (SOP only); and
(e) The service fee listed in Sec. 250.125 of this subpart.

[76 FR 64462, Oct. 18, 2011, as amended at 82 FR 26744, June 9, 2017]

Sec. 250.172 When may the Regional Supervisor grant or direct an SOO or SOP?

The Regional Supervisor may grant or direct an SOO or SOP under any
of the following circumstances:
(a) When necessary to comply with judicial decrees prohibiting any
activities or the permitting of those activities. The effective date of
the suspension will be the effective date required by the action of the
court;
(b) When activities pose a threat of serious, irreparable, or
immediate harm or damage. This would include a threat to life (including
fish and other aquatic life), property, any mineral deposit, or the
marine, coastal, or human environment. BSEE may require you to do a
site-specific study (see Sec. 250.177(a)).
(c) When necessary for the installation of safety or environmental
protection equipment;
(d) When necessary to carry out the requirements of NEPA or to
conduct an environmental analysis; or
(e) When necessary to allow for inordinate delays encountered in
obtaining required permits or consents, including administrative or
judicial challenges or appeals.

Sec. 250.173 When may the Regional Supervisor direct an SOO or SOP?

The Regional Supervisor may direct a suspension when:
(a) You failed to comply with an applicable law, regulation, order,
or provision of a lease or permit; or
(b) The suspension is in the interest of National security or
defense.

Sec. 250.174 When may the Regional Supervisor grant or direct an SOP?

The Regional Supervisor may grant or direct an SOP when the
suspension is in the National interest, and it is necessary because the
suspension will meet one of the following criteria:
(a) It will allow you to properly develop a lease, including time to
construct and install production facilities;
(b) It will allow you time to obtain adequate transportation
facilities;
(c) It will allow you time to enter a sales contract for oil, gas,
or sulphur. You must show that you are making an effort to enter into
the contract(s); or
(d) It will avoid continued operations that would result in
premature abandonment of a producing well(s).

Sec. 250.175 When may the Regional Supervisor grant an SOO?

(a) The Regional Supervisor may grant an SOO when necessary to allow
you time to begin drilling or other operations when you are prevented by
reasons beyond your control, such as unexpected weather, unavoidable
accidents, or drilling rig delays.
(b) The Regional Supervisor may grant an SOO when all of the
following conditions are met:
(1) The lease was issued with a primary lease term of 5 years, or
with a primary term of 8 years with a requirement to drill within 5
years;
(2) Before the end of the third year of the primary term, you or
your predecessor in interest must have acquired and interpreted
geophysical information that indicates:
(i) The presence of a salt sheet;

[[Page 70]]

(ii) That all or a portion of a potential hydrocarbon-bearing
formation may lie beneath or adjacent to the salt sheet; and
(iii) The salt sheet interferes with identification of the potential
hydrocarbon-bearing formation.
(3) The interpreted geophysical information required under paragraph
(b)(2) of this section must include full 3-D depth migration beneath the
salt sheet and over the entire lease area.
(4) Before requesting the suspension, you have conducted or are
conducting additional data processing or interpretation of the
geophysical information with the objective of identifying a potential
hydrocarbon-bearing formation.
(5) You demonstrate that additional time is necessary to:
(i) Complete current processing or interpretation of existing
geophysical data or information;
(ii) Acquire, process, or interpret new geophysical data or
information; or
(iii) Drill into the potential hydrocarbon-bearing formation
identified as a result of the activities conducted in paragraphs (b)(2),
(b)(4), and (b)(5) of this section.
(c) The Regional Supervisor may grant an SOO to conduct additional
geological and geophysical data analysis that may lead to the drilling
of a well below 25,000 feet true vertical depth below the datum at mean
sea level (TVD SS) when all of the following conditions are met:
(1) The lease was issued with a primary lease term of:
(i) Five years; or
(ii) Eight years with a requirement to drill within 5 years.
(2) Before the end of the fifth year of the primary term, you or
your predecessor in interest must have acquired and interpreted
geophysical information that:
(i) Indicates that all or a portion of a potential hydrocarbon-
bearing formation lies below 25,000 feet TVD SS; and
(ii) Includes full 3-D depth migration over the entire lease area.
(3) Before requesting the suspension, you have conducted or are
conducting additional data processing or interpretation of the
geophysical information with the objective of identifying a potential
hydrocarbon-bearing geologic structure or stratigraphic trap lying below
25,000 feet TVD SS.
(4) You demonstrate that additional time is necessary to:
(i) Complete current processing or interpretation of existing
geophysical data or information;
(ii) Acquire, process, or interpret new geophysical or geological
data or information that would affect the decision to drill the same
geologic structure or stratigraphic trap, as determined by the Regional
Supervisor, identified in paragraphs (c)(2) and (c)(3) of this section;
or
(iii) Drill a well below 25,000 feet TVD SS into the geologic
structure or stratigraphic trap identified as a result of the activities
conducted in paragraphs (c)(2), (c)(3), and (c)(4)(i) and (ii) of this
section.

Sec. 250.176 Does a suspension affect my royalty payment?

A directed suspension may affect the payment of rental or royalties
for the lease as provided in 30 CFR 1218.154.

Sec. 250.177 What additional requirements may the Regional Supervisor order
for a suspension?

If BSEE grants or directs a suspension under paragraph Sec.
250.172(b), the Regional Supervisor may require you to:
(a) Conduct a site-specific study.
(1) The Regional Supervisor must approve or prescribe the scope for
any site-specific study that you perform.
(2) The study must evaluate the cause of the hazard, the potential
damage, and the available mitigation measures.
(3) You must pay for the study unless you request, and the Regional
Supervisor agrees to arrange, payment by another party.
(4) You must furnish copies and results of the study to the Regional
Supervisor.
(5) BSEE will make the results available to other interested parties
and to the public.
(6) The Regional Supervisor will use the results of the study and
any other information that becomes available:
(i) To decide if the suspension can be lifted; and

[[Page 71]]

(ii) To determine any actions that you must take to mitigate or
avoid any damage to the environment, life, or property.
(b) Submit a revised Exploration Plan (including any required
mitigating measures);
(c) Submit a revised Development and Production Plan (including any
required mitigating measures); or
(d) Submit a revised Development Operations Coordination Document
according to 30 CFR part 550, subpart B.

Primary Lease Requirements, Lease Term Extensions, and Lease
Cancellations

Sec. 250.180 What am I required to do to keep my lease term in effect?

(a) If your lease is in its primary term:
(1) You must submit a report to the District Manager according to
paragraphs (h) and (i) of this section whenever production begins
initially, whenever production ceases during the last year of the
primary term, and whenever production resumes during the last year of
the primary term.
(2) Your lease expires at the end of its primary term unless you are
conducting operations on your lease (see 30 CFR part 556). For purposes
of this section, the term operations means, drilling, well-reworking, or
production in paying quantities. The objective of the drilling or well-
reworking must be to establish production in paying quantities on the
lease.
(b) If you stop conducting operations during the last year of your
primary lease term, your lease will expire unless you either resume
operations or receive an SOO or an SOP from the Regional Supervisor
under Sec. 250.172, Sec. 250.173, Sec. 250.174, or Sec. 250.175
before the end of the year after you stop operations.
(c) If you extend your lease term under paragraph (b) of this
section, you must pay rental or minimum royalty, as appropriate, for
each year or part of the year during which your lease continues in force
beyond the end of the primary lease term.
(d) If you stop conducting operations on a lease that has continued
beyond its primary term, your lease will expire unless you resume
operations or receive an SOO or an SOP from the Regional Supervisor
under Sec. 250.172, Sec. 250.173, Sec. 250.174, or Sec. 250.175
before the end of the year after you stop operations.
(e) You may ask the Regional Supervisor to allow you more than a
year to resume operations on a lease continued beyond its primary term
when operating conditions warrant. The request must be in writing and
explain the operating conditions that warrant a longer period. In
allowing additional time, the Regional Supervisor must determine that
the longer period is in the National interest, and it conserves
resources, prevents waste, or protects correlative rights.
(f) When you begin conducting operations on a lease that has
continued beyond its primary term, you must immediately notify the
District Manager either orally or by fax or e-mail and follow up with a
written report according to paragraph (g) of this section.
(g) If your lease is continued beyond its primary term, you must
submit a report to the District Manager under paragraphs (h) and (i) of
this section whenever production begins initially, whenever production
ceases, whenever production resumes before the end of the 1-year period
after having ceased, or whenever drilling or well-reworking operations
begin before the end of the 1-year period.
(h) The reports required by paragraphs (a) and (g) of this section
must contain:
(1) Name of lessee or operator;
(2) The well number, lease number, area, and block;
(3) As appropriate, the unit agreement name and number; and
(4) A description of the operation and pertinent dates.
(i) You must submit the reports required by paragraphs (a) and (g)
of this section within the following timeframes:
(1) Initialization of production--within 5 days of initial
production.
(2) Cessation of production--within 15 days after the first full
month of zero production.
(3) Resumption of production--within 5 days of resuming production
after

[[Page 72]]

ceasing production under paragraph (i)(2) of this section.
(4) Drilling or well reworking operations--within 5 days of
beginning and completing the leaseholding operations.
(j) For leases continued beyond the primary term, you must
immediately report to the District Manager if operations do not begin
before the end of the 1-year period.

[76 FR 64462, Oct. 18, 2011, as amended at 82 FR 26744, June 9, 2017]

Sec. Sec. 250.181-250.185 [Reserved]

Information and Reporting Requirements

Sec. 250.186 What reporting information and report forms must I submit?

(a) You must submit information and reports as BSEE requires.
(1) You may obtain copies of forms from, and submit completed forms
to, the District Manager or Regional Supervisor.
(2) Instead of paper copies of forms available from the District
Manager or Regional Supervisor, you may use your own computer-generated
forms that are equal in size to BSEE's forms. You must arrange the data
on your form identical to the BSEE form. If you generate your own form
and it omits terms and conditions contained on the official BSEE form,
we will consider it to contain the omitted terms and conditions.
(3) You may submit digital data when the Region/District is equipped
to accept it.
(b) When BSEE specifies, you must include, for public information,
an additional copy of such reports.
(1) You must mark it Public Information
(2) You must include all required information, except information
exempt from public disclosure under Sec. 250.197 or otherwise exempt
from public disclosure under law or regulation.

Sec. 250.187 What are BSEE's incident reporting requirements?

(a) You must report all incidents listed in Sec. 250.188(a) and (b)
to the District Manager. The specific reporting requirements for these
incidents are contained in Sec. Sec. 250.189 and 250.190.
(b) These reporting requirements apply to incidents that occur on
the area covered by your lease, right-of-use and easement, pipeline
right-of-way, or other permit issued by BOEM or BSEE, and that are
related to operations resulting from the exercise of your rights under
your lease, right-of-use and easement, pipeline right-of-way, or permit.
(c) Nothing in this subpart relieves you from making notifications
and reports of incidents that may be required by other regulatory
agencies.
(d) You must report all spills of oil or other liquid pollutants in
accordance with 30 CFR 254.46.

Sec. 250.188 What incidents must I report to BSEE and when
must I report them?

(a) You must report the following incidents to the District Manager
immediately via oral communication, and provide a written follow-up
report (hard copy or electronically transmitted) within 15 calendar days
after the incident:
(1) All fatalities.
(2) All injuries that require the evacuation of the injured
person(s) from the facility to shore or to another offshore facility.
(3) All losses of well control. ``Loss of well control'' means:
(i) Uncontrolled flow of formation or other fluids. The flow may be
to an exposed formation (an underground blowout) or at the surface (a
surface blowout);
(ii) Flow through a diverter; or
(iii) Uncontrolled flow resulting from a failure of surface
equipment or procedures.
(4) All fires and explosions.
(5) All reportable releases of hydrogen sulfide (H2S)
gas, as defined in Sec. 250.490(l).
(6) All collisions that result in property or equipment damage
greater than $25,000. ``Collision'' means the act of a moving vessel
(including an aircraft) striking another vessel, or striking a
stationary vessel or object (e.g., a boat striking a drilling rig or
platform). ``Property or equipment damage'' means the cost of labor and
material to

[[Page 73]]

restore all affected items to their condition before the damage,
including, but not limited to, the OCS facility, a vessel, helicopter,
or equipment. It does not include the cost of salvage, cleaning, gas-
freeing, dry docking, or demurrage.
(7) All incidents involving structural damage to an OCS facility.
``Structural damage'' means damage severe enough so that operations on
the facility cannot continue until repairs are made.
(8) All incidents involving crane or personnel/material handling
operations.
(9) All incidents that damage or disable safety systems or equipment
(including firefighting systems).
(b) You must provide a written report of the following incidents to
the District Manager within 15 calendar days after the incident:
(1) Any injuries that result in one or more days away from work or
one or more days on restricted work or job transfer. One or more days
means the injured person was not able to return to work or to all of
their normal duties the day after the injury occurred;
(2) All gas releases that initiate equipment or process shutdown;
(3) All incidents that require operations personnel on the facility
to muster for evacuation for reasons not related to weather or drills;
(4) All other incidents, not listed in paragraph (a) of this
section, resulting in property or equipment damage greater than $25,000.
(c) On the Arctic OCS, in addition to the requirements of paragraphs
(a) and (b) of this section, you must provide to the BSEE inspector on
location, if one is present, or to the Regional Supervisor, both of the
following:
(1) An immediate oral report if any of the following occur:
(i) Any sea ice movement or condition that has the potential to
affect your operation or trigger ice management activities;
(ii) The start and termination of ice management activities; or
(iii) Any ``kicks'' or operational issues that are unexpected and
could result in the loss of well control.
(2) Within 24 hours after completing ice management activities, a
written report of such activities that conforms to the content
requirements in Sec. 250.190.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 46560, July 15, 2016]

Sec. 250.189 Reporting requirements for incidents requiring
immediate notification.

For an incident requiring immediate notification under Sec.
250.188(a), you must notify the District Manager via oral communication
immediately after aiding the injured and stabilizing the situation. Your
oral communication must provide the following information:
(a) Date and time of occurrence;
(b) Operator, and operator representative's, name and telephone
number;
(c) Contractor, and contractor representative's name and telephone
number (if a contractor is involved in the incident or injury/fatality);
(d) Lease number, OCS area, and block;
(e) Platform/facility name and number, or pipeline segment number;
(f) Type of incident or injury/fatality;
(g) Operation or activity at time of incident (i.e., drilling,
production, workover, completion, pipeline, crane, etc.); and
(h) Description of the incident, damage, or injury/fatality.

Sec. 250.190 Reporting requirements for incidents requiring
written notification.

(a) For any incident covered under Sec. 250.188, you must submit a
written report within 15 calendar days after the incident to the
District Manager. The report must contain the following information:
(1) Date and time of occurrence;
(2) Operator, and operator representative's name and telephone
number;
(3) Contractor, and contractor representative's name and telephone
number (if a contractor is involved in the incident or injury);
(4) Lease number, OCS area, and block;
(5) Platform/facility name and number, or pipeline segment number;
(6) Type of incident or injury;
(7) Operation or activity at time of incident (i.e., drilling,
production, workover, completion, pipeline, crane etc.);

[[Page 74]]

(8) Description of incident, damage, or injury (including days away
from work, restricted work or job transfer), and any corrective action
taken; and
(9) Property or equipment damage estimate (in U.S. dollars).
(b) You may submit a report or form prepared for another agency in
lieu of the written report required by paragraph (a) of this section,
provided the report or form contains all required information.
(c) The District Manager may require you to submit additional
information about an incident on a case-by-case basis.

Sec. 250.191 How does BSEE conduct incident investigations?

Any investigation that BSEE conducts under the authority of sections
22(d)(1) and (2) of the Act (43 U.S.C. 1348(d)(1) and (2)) is a fact-
finding proceeding with no adverse parties. The purpose of the
investigation is to prepare a public report that determines the cause or
causes of the incident. The investigation may involve panel meetings
conducted by a chairperson appointed by BSEE. The following requirements
apply to any panel meetings involving persons giving testimony:
(a) A person giving testimony may have legal or other
representative(s) present to provide advice or counsel while the person
is giving testimony. The chairperson may require a verbatim transcript
to be made of all oral testimony. The chairperson also may accept a
sworn written statement in lieu of oral testimony.
(b) Only panel members, and any experts the panel deems necessary,
may address questions to any person giving testimony.
(c) The chairperson may issue subpoenas to persons to appear and
provide testimony or documents at a panel meeting. A subpoena may not
require a person to attend a panel meeting held at a location more than
100 miles from where a subpoena is served.
(d) Any person giving testimony may request compensation for
mileage, and fees for services, within 90 days after the panel meeting.
The compensated expenses must be similar to mileage and fees the U.S.
District Courts allow.

Sec. 250.192 What reports and statistics must I submit relating to
a hurricane, earthquake, or other natural occurrence?

(a) You must submit evacuation statistics to the Regional Supervisor
for a natural occurrence, such as a hurricane, a tropical storm, or an
earthquake. Statistics include facilities and rigs evacuated and the
amount of production shut-in for gas and oil. You must:
(1) Submit the statistics by fax or e-mail (for activities in the
BSEE GOM OCS Region, use Form BSEE-0132) as soon as possible when
evacuation occurs. In lieu of submitting your statistics by fax or e-
mail, you may submit them electronically in accordance with 30 CFR
250.186(a)(3);
(2) Submit the statistics on a daily basis by 11 a.m., as conditions
allow, during the period of shut-in and evacuation;
(3) Inform BSEE when you resume production; and
(4) Submit the statistics either by BSEE district, or the total
figures for your operations in a BSEE region.
(b) If your facility, production equipment, or pipeline is damaged
by a natural occurrence, you must:
(1) Submit an initial damage report to the Regional Supervisor
within 48 hours after you complete your initial evaluation of the
damage. You must use Form BSEE-0143, Facility/Equipment Damage Report,
to make this and all subsequent reports. In lieu of submitting Form
BSEE-0143 by fax or e-mail, you may submit the damage report
electronically in accordance with 30 CFR 250.186(a)(3). In the report,
you must:
(i) Name the items damaged (e.g., platform or other structure,
production equipment, pipeline);
(ii) Describe the damage and assess the extent of the damage (major,
medium, minor); and
(iii) Estimate the time it will take to replace or repair each
damaged structure and piece of equipment and return it to service. The
initial estimate need not be provided on the form until availability of
hardware and repair capability has been established (not to exceed 30
days from your initial report).

[[Page 75]]

(2) Submit subsequent reports monthly and immediately whenever
information submitted in previous reports changes until the damaged
structure or equipment is returned to service. In the final report, you
must provide the date the item was returned to service.

Sec. 250.193 Reports and investigations of possible violations.

(a) Any person may report to BSEE any hazardous or unsafe working
condition on any facility engaged in OCS activities, and any possible
violation or failure to comply with:
(1) Any provision of the Act,
(2) Any provision of a lease, approved plan, or permit issued under
the Act,
(3) Any provision of any regulation or order issued under the Act,
or
(4) Any other Federal law relating to safety of offshore oil and gas
operations.
(b) To make a report under this section, a person is not required to
know whether any legal requirement listed in paragraph (a) of this
section has been violated.
(c) When BSEE receives a report of a possible violation, or when a
BSEE employee detects a possible violation, BSEE will investigate
according to BSEE procedures and notify any other Federal agency(ies)
for further investigation, as appropriate.
(d) BSEE investigations of possible violations may include:
(1) Conducting interviews of personnel;
(2) Requiring the prompt production of documents, data, and other
evidence;
(3) Requiring the preservation of all relevant evidence and access
for BSEE investigators to such evidence; and
(4) Taking other actions and imposing other requirements as
necessary to investigate possible violations and assure an orderly
investigation.
(e)(1) Reports should contain sufficient credible information to
establish a reasonable basis for BSEE to investigate whether a violation
or other hazardous or unsafe working condition exists.
(2) To report hazardous or unsafe working conditions or a possible
violation:
(i) Contact BSEE by:
(A) Phone at 1-877-440-0173 (BSEE Toll-free Safety Hotline),
(B) Internet at www.bsee.gov, or
(C) Mail to: U.S. DOI/BSEE, 1849 C Street NW., Mail Stop 5438,
Washington, DC 20240 Attention: IRU Hotline Operations.
(ii) Include the following items in the report:
(A) Name, address, and telephone number should be provided if you do
not want to remain anonymous;
(B) The specific concern, provision or Federal law, if known,
referenced in (a) that a person violated or with which a person failed
to comply; and
(C) Any other facts, data, and applicable information.
(f) When a possible violation is reported, BSEE will protect a
person's identity to the extent authorized by law.

[78 FR 20439, Apr. 5, 2013, as amended at 81 FR 36149, June 6, 2016]

Sec. 250.194 How must I protect archaeological resources?

(a)-(b) [Reserved]
(c) If you discover any archaeological resource while conducting
operations in the lease or right-of-way area, you must immediately halt
operations within the area of the discovery and report the discovery to
the BSEE Regional Director. If investigations determine that the
resource is significant, the Regional Director will tell you how to
protect it.

Sec. 250.195 What notification does BSEE require on
the production status of wells?

You must notify the appropriate BSEE District Manager when you
successfully complete or recomplete a well for production. You must:
(a) Notify the District Manager within 5 working days of placing the
well in a production status. You must confirm oral notification by
telefax or e-mail within those 5 working days.
(b) Provide the following information in your notification:
(1) Lessee or operator name;
(2) Well number, lease number, and OCS area and block designations;
(3) Date you placed the well on production (indicate whether or not
this is first production on the lease);

[[Page 76]]

(4) Type of production; and
(5) Measured depth of the production interval.

Sec. 250.196 Reimbursements for reproduction and processing costs.

(a) BSEE will reimburse you for costs of reproducing data and
information that the Regional Director requests if:
(1) You deliver geophysical and geological (G&G) data and
information to BSEE for the Regional Director to inspect or select and
retain;
(2) BSEE receives your request for reimbursement and the Regional
Director determines that the requested reimbursement is proper; and
(3) The cost is at your lowest rate or at the lowest commercial rate
established in the area, whichever is less.
(b) BSEE will reimburse you for the costs of processing geophysical
information (that does not include cost of data acquisition):
(1) If, at the request of the Regional Director, you processed the
geophysical data or information in a form or manner other than that used
in the normal conduct of business; or
(2) If you collected the information under a permit that BSEE issued
to you before October 1, 1985, and the Regional Director requests and
retains the information.
(c) When you request reimbursement, you must identify reproduction
and processing costs separately from acquisition costs.
(d) BSEE will not reimburse you for data acquisition costs or for
the costs of analyzing or processing geological information or
interpreting geological or geophysical information.

Sec. 250.197 Data and information to be made available to the public
or for limited inspection.

BSEE will protect data and information that you submit under this
part, and 30 CFR part 203, as described in this section. Paragraphs (a)
and (b) of this section describe what data and information will be made
available to the public without the consent of the lessee, under what
circumstances, and in what time period. Paragraph (c) of this section
describes what data and information will be made available for limited
inspection without the consent of the lessee, and under what
circumstances.
(a) All data and information you submit on BSEE forms will be made
available to the public upon submission, except as specified in the
following table:

------------------------------------------------------------------------
Data and information
not immediately Excepted data will
On form . . . available are . . . be made available .
. .
------------------------------------------------------------------------
(1) BSEE-0123, Application Items 15, 16, 22 When the well goes
for Permit to Drill, through 25, on production or
according to the
table in paragraph
(b) of this
section, whichever
is earlier.
(2) BSEE-0123S, Supplemental Items 3, 7, 8, 15 When the well goes
APD Information Sheet, and 17, on production or
according to the
table in paragraph
(b) of this
section, whichever
is earlier.
(3) BSEE-0124, Application Item 17, When the well goes
for Permit to Modify, on production or
according to the
table in paragraph
(b) of this
section, whichever
is earlier.
(4) BSEE-0125, End of Items 12, 13, 17, When the well goes
Operations Report, 21, 22, 26 through on production or
38, according to the
table in paragraph
(b) of this
section, whichever
is earlier.
However, items 33
through 38 will not
be released when
the well goes on
production unless
the period of time
in the table in
paragraph (b) has
expired.
(5) BSEE-0126, Well Item 101, 2 years after you
Potential Test Report, submit it.
(6) [Reserved]
(7) BSEE-0133 Well Activity Item 10 Fields When the well goes
Report, [WELLBORE START on production or
DATE, TD DATE, OP according to the
STATUS, END DATE, table in paragraph
MD, TVD, AND MW (b) of this
PPG]. Item 11 section, whichever
Fields [WELLBORE is earlier.
START DATE, TD
DATE, PLUGBACK
DATE, FINAL MD, AND
FINAL TVD] and
Items 12 through
15,
(8) BSEE-0133S Open Hole Boxes 7 and 8, When the well goes
Data Report, on production or
according to the
table in paragraph
(b) of this
section, whichever
is earlier.
(9) [Reserved]

[[Page 77]]

(10) [Reserved]
------------------------------------------------------------------------

(b) BSEE will release lease and permit data and information that you
submit and BSEE retains, but that are not normally submitted on BSEE
forms, according to the following table:

------------------------------------------------------------------------
Special
If . . . BSEE will release At this time . . provisions . .
. . . . .
------------------------------------------------------------------------
(1) The Director Geophysical data, At any time, BSEE will
determines that Geological data release data
data and Interpreted G&G and
information are information, information
needed for Processed G&G only if
specific information, release would
scientific or Analyzed further the
research geological National
purposes for the information, interest
Government, without unduly
damaging the
competitive
position of
the lessee.
(2) Data or Geophysical data, 60 days after BSEE will
information is Geological data, BSEE receives release the
collected with Interpreted G&G the data or data and
high-resolution information, information, if information
systems (e.g., Processed the Regional earlier than
bathymetry, side- geological Supervisor deems 60 days if the
scan sonar, information, it necessary, Regional
subbottom Analyzed Supervisor
profiler, and geological determines it
magnetometer) to information, is needed by
comply with affected
safety or States to make
environmental decisions
protection under 30 CFR
requirements, 550, subpart
B. The
Regional
Supervisor
will
reconsider
earlier
release if you
satisfy him/
her that it
would unduly
damage your
competitive
position.
(3) Your lease is Geophysical data, When your lease This release
no longer in Geological data, terminates, time applies
effect, Processed G&G only if the
information provisions in
Interpreted G&G this table
information, governing high-
Analyzed resolution
geological systems and
information, the provisions
in 30 CFR
552.7 do not
apply. The
release time
applies to the
geophysical
data and
information
only if
acquired
postlease for
a lessee's
exclusive use.
(4) Your lease is Geophysical data, 10 years after This release
still in effect, Processed you submit the time applies
geophysical data and only if the
information, information, provisions in
Interpreted G&G this table
information, governing high-
resolution
systems and
the provisions
in 30 CFR
552.7 do not
apply. This
release time
applies to the
geophysical
data and
information
only if
acquired
postlease for
a lessee's
exclusive use.
(5) Your lease is Geological data, 2 years after the These release
still in effect Analyzed required times apply
and within the geological submittal date only if the
primary term information, or 60 days after provisions in
specified in the a lease sale if this table
lease, any portion of governing high-
an offered lease resolution
is within 50 systems and
miles of a well, the provisions
whichever is in 30 CFR
later, 552.7 do not
apply. If the
primary term
specified in
the lease is
extended under
the heading of
``Suspensions'
' in this
subpart, the
extension
applies to
this
provision.
(6) Your lease is Geological data, 2 years after the None.
in effect and Analyzed required
beyond the geological submittal date,
primary term information,
specified in the
lease,
(7) Data or Descriptions of When the well Directional
information is downhole goes on survey data
submitted on locations, production or may be
well operations, operations, and when geological released
equipment, data is released earlier to the
according to owner of an
Sec. Sec. adjacent lease
250.197(b)(5) according to
and (b)(6), Subpart D of
whichever occurs this part.
earlier,

[[Page 78]]

(8) Data and Any data or At any time, None.
information are information
obtained from obtained,
beneath unleased
land as a result
of a well
deviation that
has not been
approved by the
District Manager
or Regional
Supervisor,
(9) Except for G&G data, Geological data None.
high-resolution analyzed and information:
data and geological 10 years after
information information, BOEM issues the
released under processed and permit;
paragraph (b)(2) interpreted G&G Geophysical
of this section information, data: 50 years
data and after BOEM
information issues the
acquired by a permit;
permit under 30 Geophysical
CFR part 551 are information: 25
submitted by a years after BOEM
lessee under 30 issues the
CFR part 203, 30 permit,
CFR part 250, or
30 CFR part 550,
------------------------------------------------------------------------

(c) BSEE may allow limited inspection, but only by persons with a
direct interest in related BSEE decisions and issues in specific
geographic areas, and who agree in writing to its confidentiality, of
G&G data and information submitted under this part or 30 CFR part 203
that BSEE uses to:
(1) Make unitization determinations on two or more leases;
(2) Make competitive reservoir determinations;
(3) Ensure proper plans of development for competitive reservoirs;
(4) Promote operational safety;
(5) Protect the environment;
(6) [Reserved]; or
(7) Determine eligibility for royalty relief.

References

Sec. 250.198 Documents incorporated by reference.

(a) The BSEE is incorporating by reference the documents listed in
paragraphs (e) through (k) of this section. Paragraphs (e) through (k)
identify the publishing organization of the documents, the address and
phone number where you may obtain these documents, and the documents
incorporated by reference. The Director of the Federal Register has
approved the incorporations by reference according to 5 U.S.C. 552(a)
and 1 CFR part 51.
(1) Incorporation by reference of a document is limited to the
edition of the publication that is cited in this section. Future
amendments or revisions of the document are not included. The BSEE will
publish any changes to a document in the Federal Register and amend this
section.
(2) The BSEE may make the rule amending the document effective
without prior opportunity for public comment when BSEE determines:
(i) That the revisions to a document result in safety improvements
or represent new industry standard technology and do not impose undue
costs on the affected parties; and
(ii) The BSEE meets the requirements for making a rule immediately
effective under 5 U.S.C. 553.
(3) The effect of incorporation by reference of a document into the
regulations in this part is that the incorporated document is a
requirement. When a section in this part incorporates all of a document,
you are responsible for complying with the provisions of that entire
document, except to the extent that the section which incorporates the
document by reference provides otherwise. When a section in this part
incorporates part of a document, you are responsible for complying with
that part of the document as provided in that section.
(b) The BSEE incorporated each document or specific portion by
reference in the sections noted. The entire document is incorporated by
reference, unless the text of the corresponding sections in this part
calls for compliance with specific portions of the listed documents. In
each instance, the applicable document is the specific edition or
specific edition and supplement or addendum cited in this section.
(c) Under Sec. Sec. 250.141 and 250.142, you may comply with a
later edition of a

[[Page 79]]

specific document incorporated by reference, provided:
(1) You show that complying with the later edition provides a degree
of protection, safety, or performance equal to or better than would be
achieved by compliance with the listed edition; and
(2) You obtain the prior written approval for alternative compliance
from the authorized BSEE official.
(d) You may inspect these documents at the Bureau of Safety and
Environmental Enforcement, 45600 Woodland Rd, Sterling, VA 20166; phone:
1-844-259-4779; or at the National Archives and Records Administration
(NARA). For information on the availability of this material at NARA,
call 202-741-6030, or go to: http://www.archives.gov/federal_register/
code_of_ federal_regulations/ibr_locations.html.
(e) American Concrete Institute (ACI), ACI Standards, 38800 Country
Club Drive, Farmington Hills, MI 48331-3439: http://www.concrete.org;
phone: 248-848-3700:
(1) ACI Standard 318-95, Building Code Requirements for Reinforced
Concrete (ACI 318-95), incorporated by reference at Sec. 250.901.
(2) ACI 318R-95, Commentary on Building Code Requirements for
Reinforced Concrete, incorporated by reference at Sec. 250.901.
(3) ACI 357R-84, Guide for the Design and Construction of Fixed
Offshore Concrete Structures, 1984; reapproved 1997, incorporated by
reference at Sec. 250.901.
(f) American Institute of Steel Construction, Inc. (AISC), AISC
Standards, One East Wacker Drive, Suite 700, Chicago, IL 60601-1802;
http://www.aisc.org; phone: 312-670-2400:
(1) ANSI/AISC 360-05, Specification for Structural Steel Buildings
incorporated by reference at Sec. 250.901.
(2) [Reserved]
(g) American National Standards Institute (ANSI), ANSI/ASME Codes,
http://www.webstore.ansi.org; phone: 212-642-4900; and/or American
Society of Mechanical Engineers (ASME), 22 Law Drive, P.O. Box 2900,
Fairfield, NJ 07007-2900; http://www.asme.org; phone: 1-800-843-2763:
(1) ANSI/ASME Boiler and Pressure Vessel Code, Section I, Rules for
Construction of Power Boilers; including Appendices, 2004 Edition; and
July 1, 2005 Addenda, and all Section I Interpretations Volume 55,
incorporated by reference at Sec. Sec. 250.851(a) and 250.1629(b).
(2) ANSI/ASME Boiler and Pressure Vessel Code, Section IV, Rules for
Construction of Heating Boilers; including Appendices 1, 2, 3, 5, 6, and
Non-mandatory Appendices B, C, D, E, F, H, I, K, L, and M, and the Guide
to Manufacturers Data Report Forms, 2004 Edition; July 1, 2005 Addenda,
and all Section IV Interpretations Volume 55, incorporated by reference
at Sec. Sec. 250.851(a) and 250.1629(b).
(3) ANSI/ASME Boiler and Pressure Vessel Code, Section VIII, Rules
for Construction of Pressure Vessels; Divisions 1 and 2, 2004 Edition;
July 1, 2005 Addenda, Divisions 1, 2, and 3 and all Section VIII
Interpretations Volumes 54 and 55, incorporated by reference at
Sec. Sec. 250.851(a) and 250.1629(b).
(4) ANSI/ASME B 16.5-2003, Pipe Flanges and Flanged Fittings
incorporated by reference at Sec. 250.1002;
(5) ANSI/ASME B 31.8-2003, Gas Transmission and Distribution Piping
Systems incorporated by reference at Sec. 250.1002;
(6) ANSI Z88.2-1992, American National Standard for Respiratory
Protection, incorporated by reference at, Sec. 250.490.
(h) American Petroleum Institute (API), API Recommended Practices
(RP), Specs, Standards, Manual of Petroleum Measurement Standards (MPMS)
chapters, 1220 L Street, NW., Washington, DC 20005-4070; http://
www.api.org; phone: 202-682-8000:
(1) API 510, Pressure Vessel Inspection Code: In-Service Inspection,
Rating, Repair, and Alteration, Downstream Segment, Ninth Edition, June
2006; incorporated by reference at Sec. Sec. 250.851(a) and
250.1629(b);
(2) API Bulletin 2INT-DG, Interim Guidance for Design of Offshore
Structures for Hurricane Conditions, May 2007; incorporated by reference
at Sec. 250.901;
(3) API Bulletin 2INT-EX, Interim Guidance for Assessment of
Existing Offshore Structures for Hurricane Conditions, May 2007;
incorporated by reference at Sec. 250.901;
(4) API Bulletin 2INT-MET, Interim Guidance on Hurricane Conditions
in

[[Page 80]]

the Gulf of Mexico, May 2007; incorporated by reference at Sec.
250.901;
(5) API MPMS, Chapter 1--Vocabulary, Second Edition, July 1994;
incorporated by reference at Sec. 250.1201;
(6) API MPMS, Chapter 2--Tank Calibration, Section 2A--Measurement
and Calibration of Upright Cylindrical Tanks by the Manual Tank
Strapping Method, First Edition, February 1995; reaffirmed February
2007; incorporated by reference at Sec. 250.1202;
(7) API MPMS, Chapter 2--Tank Calibration, Section 2B--Calibration
of Upright Cylindrical Tanks Using the Optical Reference Line Method,
First Edition, March 1989; reaffirmed, December 2007; incorporated by
reference at Sec. 250.1202;
(8) API MPMS, Chapter 3--Tank Gauging, Section 1A--Standard Practice
for the Manual Gauging of Petroleum and Petroleum Products, Second
Edition, August 2005; incorporated by reference at Sec. 250.1202;
(9) API MPMS, Chapter 3--Tank Gauging, Section 1B--Standard Practice
for Level Measurement of Liquid Hydrocarbons in Stationary Tanks by
Automatic Tank Gauging, Second Edition, June 2001, reaffirmed, October
2006; incorporated by reference at Sec. 250.1202;
(10) API MPMS, Chapter 4--Proving Systems, Section 1--Introduction,
Third Edition, February 2005; incorporated by reference at Sec.
250.1202;
(11) API MPMS, Chapter 4--Proving Systems, Section 2--Displacement
Provers, Third Edition, September 2003; incorporated by reference at
Sec. 250.1202;
(12) API MPMS, Chapter 4--Proving Systems, Section 4--Tank Provers,
Second Edition, May 1998, reaffirmed November 2005; incorporated by
reference at Sec. 250.1202;
(13) API MPMS, Chapter 4--Proving Systems, Section 5--Master-Meter
Provers, Second Edition, May 2000, reaffirmed: August 2005; incorporated
by reference at Sec. 250.1202;
(14) API MPMS, Chapter 4--Proving Systems, Section 6--Pulse
Interpolation, Second Edition, May 1999; reaffirmed 2003; incorporated
by reference at Sec. 250.1202;
(15) API MPMS, Chapter 4--Proving Systems, Section 7--Field Standard
Test Measures, Second Edition, December 1998; reaffirmed 2003;
incorporated by reference at Sec. 250.1202;
(16) API MPMS, Chapter 5--Metering, Section 1--General
Considerations for Measurement by Meters, Fourth Edition, September
2005; incorporated by reference at Sec. 250.1202;
(17) API MPMS, Chapter 5--Metering, Section 2--Measurement of Liquid
Hydrocarbons by Displacement Meters, Third Edition, September 2005;
incorporated by reference at Sec. 250.1202;
(18) API MPMS Chapter 5--Metering, Section 3--Measurement of Liquid
Hydrocarbons by Turbine Meters, Fifth Edition, September 2005;
incorporated by reference at Sec. 250.1202;
(19) API MPMS, Chapter 5--Metering, Section 4--Accessory Equipment
for Liquid Meters, Fourth Edition, September 2005; incorporated by
reference at Sec. 250.1202;
(20) API MPMS, Chapter 5--Metering, Section 5--Fidelity and Security
of Flow Measurement Pulsed-Data Transmission Systems, Second Edition,
August 2005; incorporated by reference at Sec. 250.1202;
(21) API MPMS, Chapter 6--Metering Assemblies, Section 1--Lease
Automatic Custody Transfer (LACT) Systems, Second Edition, May 1991;
reaffirmed, April 2007; incorporated by reference at Sec. 250.1202;
(22) API MPMS, Chapter 6--Metering Assemblies, Section 6--Pipeline
Metering Systems, Second Edition, May 1991; reaffirmed, February 2007;
incorporated by reference at Sec. 250.1202;
(23) API MPMS, Chapter 6--Metering Assemblies, Section 7--Metering
Viscous Hydrocarbons, Second Edition, May 1991; reaffirmed, April 2007;
incorporated by reference at Sec. 250.1202;
(24) API MPMS, Chapter 7--Temperature Determination, First Edition,
June 2001; reaffirmed, March 2007; incorporated by reference at Sec.
250.1202;
(25) API MPMS, Chapter 8--Sampling, Section 1--Standard Practice for
Manual Sampling of Petroleum and Petroleum Products, Third Edition,
October 1995; reaffirmed, March 2006; incorporated by reference at Sec.
250.1202;
(26) API MPMS, Chapter 8--Sampling, Section 2--Standard Practice for
Automatic Sampling of Liquid Petroleum and Petroleum Products, Second
Edition, October 1995; reaffirmed, June

[[Page 81]]

2005; incorporated by reference at Sec. 250.1202;
(27) API MPMS, Chapter 9--Density Determination, Section 1--Standard
Test Method for Density, Relative Density (Specific Gravity), or API
Gravity of Crude Petroleum and Liquid Petroleum Products by Hydrometer
Method, Second Edition, December 2002; reaffirmed October 2005;
incorporated by reference at Sec. 250.1202(a)(3) and (l)(4);
(28) API MPMS, Chapter 9--Density Determination, Section 2--Standard
Test Method for Density or Relative Density of Light Hydrocarbons by
Pressure Hydrometer, Second Edition, March 2003; incorporated by
reference at Sec. 250.1202;
(29) API MPMS, Chapter 10--Sediment and Water, Section 1--Standard
Test Method for Sediment in Crude Oils and Fuel Oils by the Extraction
Method, Third Edition, November 2007; incorporated by reference at Sec.
250.1202;
(30) API MPMS, Chapter 10--Sediment and Water, Section 2--Standard
Test Method for Water in Crude Oil by Distillation, Second Edition,
November 2007; incorporated by reference at Sec. 250.1202;
(31) API MPMS, Chapter 10--Sediment and Water, Section 3--Standard
Test Method for Water and Sediment in Crude Oil by the Centrifuge Method
(Laboratory Procedure), Third Edition, May 2008; incorporated by
reference at Sec. 250.1202;
(32) API MPMS, Chapter 10--Sediment and Water, Section 4--
Determination of Water and/or Sediment in Crude Oil by the Centrifuge
Method (Field Procedure), Third Edition, December 1999; incorporated by
reference at Sec. 250.1202;
(33) API MPMS, Chapter 10--Sediment and Water, Section 9--Standard
Test Method for Water in Crude Oils by Coulometric Karl Fischer
Titration, Second Edition, December 2002; reaffirmed 2005; incorporated
by reference at Sec. 250.1202;
(34) API MPMS, Chapter 11.1--Volume Correction Factors, Volume 1,
Table 5A--Generalized Crude Oils and JP-4 Correction of Observed API
Gravity to API Gravity at 60 [deg]F, and Table 6A--Generalized Crude
Oils and JP-4 Correction of Volume to 60 [deg]F Against API Gravity at
60 [deg]F, API Standard 2540, First Edition, August 1980; reaffirmed
March 1997; incorporated by reference at Sec. 250.1202;
(35) API MPMS, Chapter 11.2.2--Compressibility Factors for
Hydrocarbons: 0.350-0.637 Relative Density (60 [deg]F/60 [deg]F) and -50
[deg]F to 140 [deg]F Metering Temperature, Second Edition, October 1986;
reaffirmed: December 2007; incorporated by reference at Sec. 250.1202;
(36) API MPMS, Chapter 11--Physical Properties Data, Addendum to
Section 2, Part 2--Compressibility Factors for Hydrocarbons, Correlation
of Vapor Pressure for Commercial Natural Gas Liquids, First Edition,
December 1994; reaffirmed, December 2002; incorporated by reference at
Sec. 250.1202;
(37) API MPMS, Chapter 12--Calculation of Petroleum Quantities,
Section 2--Calculation of Petroleum Quantities Using Dynamic Measurement
Methods and Volumetric Correction Factors, Part 1--Introduction, Second
Edition, May 1995; reaffirmed March 2002; incorporated by reference at
Sec. 250.1202;
(38) API MPMS, Chapter 12--Calculation of Petroleum Quantities,
Section 2--Calculation of Petroleum Quantities Using Dynamic Measurement
Methods and Volumetric Correction Factors, Part 2--Measurement Tickets,
Third Edition, June 2003; incorporated by reference at Sec. 250.1202;
(39) API MPMS, Chapter 14--Natural Gas Fluids Measurement, Section
3--Concentric, Square-Edged Orifice Meters, Part 1--General Equations
and Uncertainty Guidelines, Third Edition, September 1990; reaffirmed
January 2003; incorporated by reference at Sec. 250.1203;
(40) API MPMS, Chapter 14--Natural Gas Fluids Measurement, Section
3--Concentric, Square-Edged Orifice Meters, Part 2--Specification and
Installation Requirements, Fourth Edition, April 2000; reaffirmed March
2006; incorporated by reference at Sec. 250.1203;
(41) API MPMS, Chapter 14--Natural Gas Fluids Measurement, Section
3--Concentric, Square-Edged Orifice Meters; Part 3--Natural Gas
Applications; Third Edition, August 1992; Errata March 1994, reaffirmed,
February 2009; incorporated by reference at Sec. 250.1203;
(42) API MPMS, Chapter 14.5/GPA Standard 2172-09; Calculation of
Gross

[[Page 82]]

Heating Value, Relative Density, Compressibility and Theoretical
Hydrocarbon Liquid Content for Natural Gas Mixtures for Custody
Transfer; Third Edition, January 2009; incorporated by reference at
Sec. 250.1203;
(43) API MPMS, Chapter 14--Natural Gas Fluids Measurement, Section
6--Continuous Density Measurement, Second Edition, April 1991;
reaffirmed, February 2006; incorporated by reference at Sec. 250.1203;
(44) API MPMS, Chapter 14--Natural Gas Fluids Measurement, Section
8--Liquefied Petroleum Gas Measurement, Second Edition, July 1997;
reaffirmed, March 2006; incorporated by reference at Sec. 250.1203;
(45) API MPMS, Chapter 20--Section 1--Allocation Measurement, First
Edition, September 1993; reaffirmed October 2006; incorporated by
reference at Sec. 250.1202;
(46) API MPMS, Chapter 21--Flow Measurement Using Electronic
Metering Systems, Section 1--Electronic Gas Measurement, First Edition,
August 1993; reaffirmed, July 2005; incorporated by reference at Sec.
250.1203;
(47) API RP 2A-WSD, Recommended Practice for Planning, Designing and
Constructing Fixed Offshore Platforms--Working Stress Design, Twenty-
first Edition, December 2000; Errata and Supplement 1, December 2002;
Errata and Supplement 2, September 2005; Errata and Supplement 3,
October 2007; incorporated by reference at Sec. Sec. 250.901, 250.908,
250.919, and 250.920;
(48) API RP 2D, Operation and Maintenance of Offshore Cranes, Sixth
Edition, May 2007; incorporated by reference at Sec. 250.108;
(49) API RP 2FPS, RP for Planning, Designing, and Constructing
Floating Production Systems; First Edition, March 2001; incorporated by
reference at Sec. 250.901;
(50) API RP 2I, In-Service Inspection of Mooring Hardware for
Floating Structures; Third Edition, April 2008; incorporated by
reference at Sec. 250.901(a) and (d);
(51) API RP 2RD, Recommended Practice for Design of Risers for
Floating Production Systems (FPSs) and Tension-Leg Platforms (TLPs),
First Edition, June 1998; reaffirmed, May 2006, Errata, June 2009;
incorporated by reference at Sec. Sec. 250.292, 250.733, 250.800(c),
250.901(a), (d), and 250.1002(b);
(52) API RP 2SK, Recommended Practice for Design and Analysis of
Stationkeeping Systems for Floating Structures, Third Edition, October
2005, Addendum, May 2008; incorporated by reference at Sec. Sec.
250.800(c) and 250.901(a), (d);
(53) API RP 2SM, Recommended Practice for Design, Manufacture,
Installation, and Maintenance of Synthetic Fiber Ropes for Offshore
Mooring, First Edition, March 2001, Addendum, May 2007; incorporated by
reference at Sec. Sec. 250.800(c) and 250.901;
(54) API RP 2T, Recommended Practice for Planning, Designing, and
Constructing Tension Leg Platforms, Second Edition, August 1997;
incorporated by reference at Sec. 250.901;
(55) ANSI/API RP 14B, Recommended Practice for Design, Installation,
Repair and Operation of Subsurface Safety Valve Systems, Fifth Edition,
October 2005; incorporated by reference at Sec. Sec. 250.802(b),
250.803(a), 250.814(d), 250.828(c), and 250.880(c);
(56) API RP 14C, Recommended Practice for Analysis, Design,
Installation, and Testing of Basic Surface Safety Systems for Offshore
Production Platforms, Seventh Edition, March 2001, Reaffirmed: March
2007; incorporated by reference at Sec. Sec. 250.125(a), 250.292(j),
250.841(a), 250.842(a), 250.850, 250.852(a), 250.855, 250.856(a),
250.858(a), 250.862(e), 250.865(a), 250.867(a), 250.869(a) through (c),
250.872(a), 250.873(a), 250.874(a), 250.880(b) and (c), 250.1002(d),
250.1004(b), 250.1628(c) and (d), 250.1629(b), and 250.1630(a);
(57) API RP 14E, Recommended Practice for Design and Installation of
Offshore Production Platform Piping Systems, Fifth Edition, October
1991; Reaffirmed, January 2013; incorporated by reference at Sec. Sec.
250.841(b), 250.842(a), and 250.1628(b) and (d);
(58) API RP 14F, Recommended Practice for Design, Installation, and
Maintenance of Electrical Systems for Fixed and Floating Offshore
Petroleum Facilities for Unclassified and Class 1, Division 1 and
Division 2 Locations, Upstream Segment, Fifth Edition, July 2008,
Reaffirmed: April 2013; incorporated by reference at Sec. Sec.
250.114(c), 250.842(b), 250.862(e), and 250.1629(b);

[[Page 83]]

(59) API RP 14FZ, Recommended Practice for Design and Installation
of Electrical Systems for Fixed and Floating Offshore Petroleum
Facilities for Unclassified and Class I, Zone 0, Zone 1 and Zone 2
Locations, First Edition, September 2001, Reaffirmed: March 2007;
incorporated by reference at Sec. Sec. 250.114(c), 250.842(b),
250.862(e), and 250.1629(b);
(60) API RP 14G, Recommended Practice for Fire Prevention and
Control on Fixed Open-type Offshore Production Platforms, Fourth
Edition, April 2007; incorporated by reference at Sec. Sec. 250.859(a),
250.862(e), 250.880(c), and 250.1629(b);
(61) API RP 14H, Recommended Practice for Installation, Maintenance
and Repair of Surface Safety Valves and Underwater Safety Valves
Offshore, Fifth Edition, August 2007; incorporated by reference at
Sec. Sec. 250.820, 250.834, 250.836, and 250.880(c);
(62) API RP 14J, Recommended Practice for Design and Hazards
Analysis for Offshore Production Facilities, Second Edition, May 2001;
Reaffirmed: January 2013; incorporated by reference at Sec. Sec.
250.800(b) and (c), 250.842(b), and 250.901(a);
(63) API Standard 53, Blowout Prevention Equipment Systems for
Drilling Wells, Fourth Edition, November 2012, incorporated by reference
at Sec. Sec. 250.730, 250.735, 250.737, and 250.739;
(64) API RP 65, Recommended Practice for Cementing Shallow Water
Flow Zones in Deepwater Wells, First Edition, September 2002;
incorporated by reference at Sec. 250.415;
(65) API RP 500, Recommended Practice for Classification of
Locations for Electrical Installations at Petroleum Facilities
Classified as Class I, Division 1 and Division 2, Second Edition,
November 1997; Errata (August 17, 1998), Reaffirmed November 2002;
incorporated by reference at Sec. Sec. 250.114(a), 250.459, 250.842(a),
250.862(a) and (e), 250.872(a), 250.1628(b) and (d), and 250.1629(b);
(66) API RP 505, Recommended Practice for Classification of
Locations for Electrical Installations at Petroleum Facilities
Classified as Class I, Zone 0, Zone 1, and Zone 2, First Edition,
November 1997; Reaffirmed, August 2013; incorporated by reference at
Sec. Sec. 250.114(a), 250.459, 250.842(a), 250.862(a) and (e),
250.872(a), 250.1628(b) and (d), and 250.1629(b);
(67) API RP 2556, Recommended Practice for Correcting Gauge Tables
for Incrustation, Second Edition, August 1993; reaffirmed November 2003;
incorporated by reference at Sec. 250.1202;
(68) ANSI/API Specification Q1 (ANSI/API Spec. Q1), Specification
for Quality Programs for the Petroleum, Petrochemical and Natural Gas
Industry, Eighth Edition, December 2007, Addendum 1, June 2010;
incorporated by reference at Sec. Sec. 250.730, 250.801(b) and (c);
(69) API Spec. 2C, Specification for Offshore Pedestal Mounted
Cranes, Sixth Edition, March 2004, Effective Date: September 2004;
incorporated by reference at Sec. 250.108;
(70) ANSI/API Specification 6A (ANSI/API Spec. 6A), Specification
for Wellhead and Christmas Tree Equipment, Nineteenth Edition, July
2004; Errata 1 (September 2004), Errata 2 (April 2005), Errata 3 (June
2006) Errata 4 (August 2007), Errata 5 (May 2009), Addendum 1 (February
2008), Addenda 2, 3, and 4 (December 2008); incorporated by reference at
Sec. Sec. 250.730, 250.802(a), 250.803(a), 250.833, 250.873(b),
250.874(g), and 250.1002(b);
(71) API Spec. 6AV1, Specification for Verification Test of Wellhead
Surface Safety Valves and Underwater Safety Valves for Offshore Service,
First Edition, February 1, 1996; reaffirmed April 2008; incorporated by
reference at Sec. Sec. 250.802(a), 250.833, 250.873(b), and 250.874(g);
(72) ANSI/API Spec. 6D, Specification for Pipeline Valves, Twenty-
third Edition, April 2008; Effective Date: October 1, 2008, Errata 1,
June 2008; Errata 2, November 2008; Errata 3, February 2009; Addendum 1,
October 2009; Contains API Monogram Annex as Part of U.S. National
Adoption; ISO 14313:2007 (Identical), Petroleum and natural gas
industries--Pipeline transportation systems--Pipeline valves;
incorporated by reference at Sec. 250.1002;
(73) ANSI/API Spec. 14A, Specification for Subsurface Safety Valve
Equipment, Eleventh Edition, October 2005, Reaffirmed, June 2012;
incorporated by reference at Sec. Sec. 250.802(b) and 250.803(a);

[[Page 84]]

(74) ANSI/API Spec. 17J, Specification for Unbonded Flexible Pipe,
Third Edition, July 2008, incorporated by reference at Sec. Sec.
250.852(e), 250.1002(b), and 250.1007(a).
(75) API Standard 2552, USA Standard Method for Measurement and
Calibration of Spheres and Spheroids, First Edition, 1966; reaffirmed,
October 2007; incorporated by reference at Sec. 250.1202;
(76) API Standard 2555, Method for Liquid Calibration of Tanks,
First Edition, September 1966; reaffirmed March 2002; incorporated by
reference at Sec. 250.1202;
(77) API RP 90, Annular Casing Pressure Management for Offshore
Wells, First Edition, August 2006, incorporated by reference at Sec.
250.518;
(78) API Standard 65--Part 2, Isolating Potential Flow Zones During
Well Construction; Second Edition, December 2010; incorporated by
reference at Sec. 250.415(f);
(79) API RP 75, Recommended Practice for Development of a Safety and
Environmental Management Program for Offshore Operations and Facilities,
Third Edition, May 2004, Reaffirmed May 2008; incorporated by reference
at Sec. Sec. 250.1900, 250.1902, 250.1903, 250.1909, 250.1920;
(80) API Manual of Petroleum Measurement Standards (MPMS) Chapter
4--Proving Systems, Section 8--Operation of Proving Systems; First
Edition, reaffirmed March 2007; incorporated by reference at Sec.
250.1202(a)(2), (a)(3), (f)(1), and (g);
(81) API Manual of Petroleum Measurement Standards (MPMS) Chapter
5--Metering, Section 6--Measurement of Liquid Hydrocarbons by Coriolis
Meters; First Edition, reaffirmed March 2008; incorporated by reference
at Sec. 250.1202(a)(2) and (3);
(82) API Manual of Petroleum Measurement Standards (MPMS) Chapter
5--Metering, Section 8--Measurement of Liquid Hydrocarbons by Ultrasonic
Flow Meters Using Transit Time Technology; First Edition, February 2005;
incorporated by reference at Sec. 250.1202(a)(2) and (3);
(83) API Manual of Petroleum Measurement Standards (MPMS) Chapter
11--Physical Properties Data, Section 1--Temperature and Pressure Volume
Correction Factors for Generalized Crude Oils, Refined Products, and
Lubricating Oils; May 2004, (incorporating Addendum 1, September 2007);
incorporated by reference at Sec. 250.1202(a)(2), (a)(3), (g), and
(l)(4);
(84) API Manual of Petroleum Measurement Standards (MPMS) Chapter
12--Calculation of Petroleum Quantities, Section 2--Calculation of
Petroleum Quantities Using Dynamic Measurement Methods and Volumetric
Correction Factors, Part 3--Proving Reports; First Edition, reaffirmed
2009; incorporated by reference at Sec. 250.1202(a)(2), (a)(3), and
(g);
(85) API Manual of Petroleum Measurement Standards (MPMS) Chapter
12--Calculation of Petroleum Quantities, Section 2--Calculation of
Petroleum Quantities Using Dynamic Measurement Methods and Volumetric
Correction Factors, Part 4--Calculation of Base Prover Volumes by the
Waterdraw Method, First Edition, reaffirmed 2009; incorporated by
reference at Sec. 250.1202(a)(2), (a)(3), (f)(1), and (g);
(86) API Manual of Petroleum Measurement Standards (MPMS) Chapter
21--Flow Measurement Using Electronic Metering Systems, Section 2--
Electronic Liquid Volume Measurement Using Positive Displacement and
Turbine Meters; First Edition, June 1998; incorporated by reference at
Sec. 250.1202(a)(2);
(87) API Manual of Petroleum Measurement Standards Chapter 21--Flow
Measurement Using Electronic Metering Systems, Addendum to Section 2--
Flow Measurement Using Electronic Metering Systems, Inferred Mass; First
Edition, reaffirmed February 2006; incorporated by reference at Sec.
250.1202(a)(2);
(88) API RP 86, API Recommended Practice for Measurement of
Multiphase Flow; First Edition, September 2005; incorporated by
reference at Sec. 250.1202(a)(2), (a)(3), and Sec. 250.1203(b)(2);
(89) ANSI/API Specification 11D1, Packers and Bridge Plugs, Second
Edition, July 2009, incorporated by reference at Sec. Sec. 250.518,
250.619, and 250.1703;
(90) ANSI/API Specification 16A, Specification for Drill-through
Equipment, Third Edition, June 2004, Reaffirmed August 2010,
incorporated by reference at Sec. 250.730;

[[Page 85]]

(91) ANSI/API Specification 16C, Specification for Choke and Kill
Systems, First Edition, January 1993, Reaffirmed July 2010; incorporated
by reference at Sec. 250.730;
(92) API Specification 16D, Specification for Control Systems for
Drilling Well Control Equipment and Control Systems for Diverter
Equipment, Second Edition, July 2004, Reaffirmed August 2013,
incorporated by reference at Sec. 250.730;
(93) ANSI/API Specification 17D, Design and Operation of Subsea
Production Systems--Subsea Wellhead and Tree Equipment, Second Edition,
May 2011, incorporated by reference at Sec. 250.730;
(94) ANSI/API Recommended Practice 17H, Remotely Operated Vehicle
Interfaces on Subsea Production Systems, First Edition, July 2004,
Reaffirmed January 2009, incorporated by reference at Sec. 250.734;
(95) ANSI/API RP 2N, Third Edition, ``Recommended Practice for
Planning, Designing, and Constructing Structures and Pipelines for
Arctic Conditions'', Third Edition, April 2015; incorporated by
reference at Sec. 250.470(g); and
(96) API 570 Piping Inspection Code: In-service Inspection, Rating,
Repair, and Alteration of Piping Systems, Third Edition, November 2009;
incorporated by reference at Sec. 250.841(b).
(i) American Society for Testing and Materials (ASTM), ASTM
Standards, 100 Bar Harbor Drive, P.O. Box C700, West Conshohocken, PA
19428-2959; http://www.astm.org; phone: 1-877-909-2786:
(1) ASTM Standard C 33-07, approved December 15, 2007, Standard
Specification for Concrete Aggregates; incorporated by reference at
Sec. 250.901;
(2) ASTM Standard C 94/C 94M-07, approved January 1, 2007, Standard
Specification for Ready-Mixed Concrete; incorporated by reference at
Sec. 250.901;
(3) ASTM Standard C 150-07, approved May 1, 2007, Standard
Specification for Portland Cement; incorporated by reference at Sec.
250.901;
(4) ASTM Standard C 330-05, approved December 15, 2005, Standard
Specification for Lightweight Aggregates for Structural Concrete;
incorporated by reference at Sec. 250.901;
(5) ASTM Standard C 595-08, approved January 1, 2008, Standard
Specification for Blended Hydraulic Cements; incorporated by reference
at Sec. 250.901;
(j) American Welding Society (AWS), AWS Codes, 8669 NW 36 Street,
130, Miami, FL 33126; http://www.aws.org; phone: 800-443-9353:
(1) AWS D1.1:2000, Structural Welding Code--Steel, 17th Edition,
October 18, 1999; incorporated by reference at Sec. 250.901;
(2) AWS D1.4-98, Structural Welding Code--Reinforcing Steel, 1998
Edition; incorporated by reference at Sec. 250.901;
(3) AWS D3.6M:1999, Specification for Underwater Welding (1999);
incorporated by reference at Sec. 250.901.
(k) National Association of Corrosion Engineers (NACE)
International, NACE Standards, Park Ten Place, Houston, TX 77084; http:/
/www.nace.org; phone: 281-228-6200:
(1) NACE Standard MR0175-2003, Standard Material Requirements,
Metals for Sulfide Stress Cracking and Stress Corrosion Cracking
Resistance in Sour Oilfield Environments, Revised January 17, 2003;
incorporated by reference at Sec. Sec. 250.901 and 250.490;
(2) NACE Standard RP0176-2003, Standard Recommended Practice,
Corrosion Control of Steel Fixed Offshore Structures Associated with
Petroleum Production; incorporated by reference at Sec. 250.901.
(l) American Gas Association (AGA Reports), 400 North Capitol
Street, NW., Suite 450, Washington, DC 20001, http://www.aga.org; phone:
202-824-7000;
(1) AGA Report No. 7--Measurement of Natural Gas by Turbine Meters;
Revised February 2006; incorporated by reference at Sec.
250.1203(b)(2);
(2) AGA Report No. 9--Measurement of Gas by Multipath Ultrasonic
Meters; Second Edition, April 2007; incorporated by reference at Sec.
250.1203(b)(2);
(3) AGA Report No. 10--Speed of Sound in Natural Gas and Other
Related Hydrocarbon Gases; Copyright 2003; incorporated by reference at
Sec. 250.1203(b)(2).
(m) International Organization for Standardization (ISO), 1, ch. de
la Voie-Creuse, CP 56, CH-1211, Geneva 20, Switzerland; www.iso.org;
phone: 41-22-749-01-11:

[[Page 86]]

(1) ISO/IEC (International Electrotechnical Commission) 17011,
Conformity assessment--General requirements for accreditation bodies
accrediting conformity assessment bodies, First edition 2004-09-01;
Corrected version 2005-02-15; incorporated by reference at Sec. Sec.
250.1900, 250.1903, 250.1904, and 250.1922.
(2) [Reserved]
(n) Center for Offshore Safety (COS), 1990 Post Oak Blvd., Suite
1370, Houston, TX 77056; www.centerforoffshoresafety.org; phone: 832-
495-4925.
(1) COS Safety Publication COS-2-01, Qualification and Competence
Requirements for Audit Teams and Auditors Performing Third-party SEMS
Audits of Deepwater Operations, First Edition, Effective Date October
2012; incorporated by reference at Sec. Sec. 250.1900, 250.1903,
250.1904, and 250.1921.
(2) COS Safety Publication COS-2-03, Requirements for Third-party
SEMS Auditing and Certification of Deepwater Operations, First Edition,
Effective Date October 2012; incorporated by reference at Sec. Sec.
250.1900, 250.1903, 250.1904, and 250.1920.
(3) COS Safety Publication COS-2-04, Requirements for Accreditation
of Audit Service Providers Performing SEMS Audits and Certification of
Deepwater Operations, First Edition, Effective Date October 2012;
incorporated by reference at Sec. Sec. 250.1900, 250.1903, 250.1904,
and 250.1922.

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 18921, Mar. 29, 2012;
77 FR 50891, Aug. 22, 2012; 78 FR 20440, Apr. 5, 2013; 81 FR 26015, Apr.
29, 2016; 81 FR 36149, June 6, 2016; 81 FR 46560, July 15, 2016; 81 FR
61917, Sept. 7, 2016]

Sec. 250.199 Paperwork Reduction Act statements--information collection.

(a) OMB has approved the information collection requirements in part
250 under 44 U.S.C. 3501 et seq. The table in paragraph (e) of this
section lists the subpart in the rule requiring the information and its
title, provides the OMB control number, and summarizes the reasons for
collecting the information and how BSEE uses the information. The
associated BSEE forms required by this part are listed at the end of
this table with the relevant information.
(b) Respondents are OCS oil, gas, and sulphur lessees and operators.
The requirement to respond to the information collections in this part
is mandated under the Act (43 U.S.C. 1331 et seq.) and the Act's
Amendments of 1978 (43 U.S.C. 1801 et seq.). Some responses are also
required to obtain or retain a benefit or may be voluntary. Proprietary
information will be protected under Sec. 250.197, Data and information
to be made available to the public or for limited inspection; parts 30
CFR Parts 251, 252; and the Freedom of Information Act (5 U.S.C. 552)
and its implementing regulations at 43 CFR part 2.
(c) The Paperwork Reduction Act of 1995 requires us to inform the
public that an agency may not conduct or sponsor, and you are not
required to respond to, a collection of information unless it displays a
currently valid OMB control number.
(d) Send comments regarding any aspect of the collections of
information under this part, including suggestions for reducing the
burden, to the Information Collection Clearance Officer, Bureau of
Safety and Environmental Enforcement, 45600 Woodland Road, Sterling, VA
20166.
(e) BSEE is collecting this information for the reasons given in the
following table:

------------------------------------------------------------------------
30 CFR Subpart, title and/or BSEE Form BSEE collects this information
(OMB Control No.) and uses it to:
------------------------------------------------------------------------
(1) Subpart A, General (1014-0022), (i) Determine that activities
including Forms BSEE-0011, iSEE; BSEE- on the OCS comply with
0132, Evacuation Statistics; BSEE-0143, statutory and regulatory
Facility/Equipment Damage Report; BSEE- requirements; are safe and
1832, Notification of Incidents of protect the environment; and
Noncompliance. result in diligent
development and production on
OCS leases.
(ii) Support the unproved and
proved reserve estimation,
resource assessment, and fair
market value determinations.
(iii) Assess damage and
project any disruption of oil
and gas production from the
OCS after a major natural
occurrence.

[[Page 87]]

(2) Subpart B, Plans and Information Evaluate Deepwater Operations
(1014-0024). Plans for compliance with
statutory and regulatory
requirements
(3) Subpart C, Pollution Prevention and (i) Evaluate measures to
Control (1014-0023). prevent unauthorized
discharge of pollutants into
the offshore waters.
(ii) Ensure action is taken to
control pollution.
(4) Subpart D, Oil and Gas and Drilling (i) Evaluate the equipment and
Operations (1014-0018), including Forms procedures to be used in
BSEE-0125, End of Operations Report; drilling operations on the
BSEE-0133, Well Activity Report; and OCS.
BSEE-0133S, Open Hole Data Report.
(ii) Ensure that drilling
operations meet statutory and
regulatory requirements.
(5) Subpart E, Oil and Gas Well- (i) Evaluate the equipment and
Completion Operations (1014-0004). procedures to be used in well-
completion operations on the
OCS.
(ii) Ensure that well-
completion operations meet
statutory and regulatory
requirements.
(6) Subpart F, Oil and Gas Well Workover (i) Evaluate the equipment and
Operations (1014-0001). procedures to be used during
well-workover operations on
the OCS.
(ii) Ensure that well-workover
operations meet statutory and
regulatory requirements.
(7) Subpart G, Blowout Preventer Systems (i) Evaluate the equipment and
(1014-0028), including Form BSEE-0144, procedures to be used during
Rig Movement Notification Report. well drilling, completion,
workover, and abandonment
operations on the OCS.
(ii) Ensure that well
operations meet statutory and
regulatory requirements.
(8) Subpart H, Oil and Gas Production (i) Evaluate the equipment and
Safety Systems (1014-0003). procedures that will be used
during production operations
on the OCS.
(ii) Ensure that production
operations meet statutory and
regulatory requirements.
(9) Subpart I, Platforms and Structures (i) Evaluate the design,
(1014-0011). fabrication, and installation
of platforms on the OCS.
(ii) Ensure the structural
integrity of platforms
installed on the OCS.
(10) Subpart J, Pipelines and Pipeline (i) Evaluate the design,
Rights-of-Way (1014-0016), including installation, and operation
Form BSEE-0149, Assignment of Federal of pipelines on the OCS.
OCS Pipeline Right-of-Way Grant.
(ii) Ensure that pipeline
operations meet statutory and
regulatory requirements.
(11) Subpart K, Oil and Gas Production (i) Evaluate production rates
Rates (1014-0019), including Forms BSEE- for hydrocarbons produced on
0126, Well Potential Test Report and the OCS.
BSEE-0128, Semiannual Well Test Report.
(ii) Ensure economic
maximization of ultimate
hydrocarbon recovery.
(12) Subpart L, Oil and Gas Production (i) Evaluate the measurement
Measurement, Surface Commingling, and of production, commingling of
Security (1014-0002). hydrocarbons, and site
security plans.
(ii) Ensure that produced
hydrocarbons are measured and
commingled to provide for
accurate royalty payments and
security.
(13) Subpart M, Unitization (1014-0015). (i) Evaluate the unitization
of leases.
(ii) Ensure that unitization
prevents waste, conserves
natural resources, and
protects correlative rights.
(14) Subpart N, Remedies and Penalties.. (The requirements in subpart N
are exempt from the Paperwork
Reduction Act of 1995
according to 5 CFR 1320.4).
(15) Subpart O, Well Control and (i) Evaluate training program
Production Safety Training (1014-0008). curricula for OCS workers,
course schedules, and
attendance.
(ii) Ensure that training
programs are technically
accurate and sufficient to
meet statutory and regulatory
requirements, and that
workers are properly trained.
(16) Subpart P, Sulfur Operations (1014- (i) Evaluate sulfur
0006). exploration and development
operations on the OCS.
(ii) Ensure that OCS sulfur
operations meet statutory and
regulatory requirements and
will result in diligent
development and production of
sulfur leases.
(17) Subpart Q, Decommissioning Ensure that decommissioning
Activities (1014-0010). activities, site clearance,
and platform or pipeline
removal are properly
performed to meet statutory
and regulatory requirements
and do not conflict with
other users of the OCS.

[[Page 88]]

(18) Subpart S, Safety and Environmental (i) Evaluate operators'
Management Systems (1014-0017), policies and procedures to
including Form BSEE-0131, Performance assure safety and
Measures Data. environmental protection
while conducting OCS
operations (including those
operations conducted by
contractor and subcontractor
personnel).
(ii) Evaluate Performance
Measures Data relating to
risk and number of accidents,
injuries, and oil spills
during OCS activities.
(19) Application for Permit to Drill (i) Evaluate and approve the
(APD, Revised APD), Form BSEE-0123; and adequacy of the equipment,
Supplemental APD Information Sheet, materials, and/or procedures
Form BSEE-0123S, and all supporting that the lessee or operator
documentation (1014-0025). plans to use during drilling.
(ii) Ensure that applicable
OCS operations meet statutory
and regulatory requirements.
(20) Application for Permit to Modify (i) Evaluate and approve the
(APM), Form BSEE-0124, and supporting adequacy of the equipment,
documentation (1014-0026). materials, and/or procedures
that the lessee or operator
plans to use during drilling
and to evaluate well plan
modifications and changes in
major equipment.
(ii) Ensure that applicable
OCS operations meet statutory
and regulatory requirements.
------------------------------------------------------------------------

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 26015, Apr. 29, 2016;
81 FR 36149, June 6, 2016]

Subpart B_Plans and Information

General Information

Sec. 250.200 Definitions.

Acronyms and terms used in this subpart have the following meanings:
(a) Acronyms used frequently in this subpart are listed
alphabetically below:
BOEM means Bureau of Ocean Energy Management of the Department of
the Interior.
BSEE means Bureau of Safety and Environmental Enforcement of the
Department of the Interior.
CID means Conservation Information Document.
CZMA means Coastal Zone Management Act.
DOCD means Development Operations Coordination Document.
DPP means Development and Production Plan.
DWOP means Deepwater Operations Plan.
EIA means Environmental Impact Analysis.
EP means Exploration Plan.
NPDES means National Pollutant Discharge Elimination System.
NTL means Notice to Lessees and Operators.
OCS means Outer Continental Shelf.
(b) Terms used in this subpart are listed alphabetically below:
Amendment means a change you make to an EP, DPP, or DOCD that is
pending before BOEM for a decision (see 30 CFR 550.232(d) and
550.267(d)).
Modification means a change required by the Regional Supervisor to
an EP, DPP, or DOCD (see 30 CFR 550.233(b)(2) and 550.270(b)(2)) that is
pending before BOEM for a decision because the OCS plan is inconsistent
with applicable requirements.
New or unusual technology means equipment or procedures that:
(1) Have not been used previously or extensively in a BSEE OCS
Region;
(2) Have not been used previously under the anticipated operating
conditions; or
(3) Have operating characteristics that are outside the performance
parameters established by this part.
Non-conventional production or completion technology includes, but
is not limited to, floating production systems, tension leg platforms,
spars, floating production, storage, and offloading systems, guyed
towers, compliant towers, subsea manifolds, and other subsea production
components that rely on a remote site or host facility for utility and
well control services.
Offshore vehicle means a vehicle that is capable of being driven on
ice.
Resubmitted OCS plan means an EP, DPP, or DOCD that contains changes
you make to an OCS plan that BOEM has disapproved (see 30 CFR
550.234(b), 550.272(a), and 550.273(b)).

[[Page 89]]

Revised OCS plan means an EP, DPP, or DOCD that proposes changes to
an approved OCS plan, such as those in the location of a well or
platform, type of drilling unit, or location of the onshore support base
(see 30 CFR 550.283(a)).
Supplemental OCS plan means an EP, DPP, or DOCD that proposes the
addition to an approved OCS plan of an activity that requires approval
of an application or permit (see 30 CFR 550.283(b)).

Sec. 250.201 What plans and information must I submit before I conduct
any activities on my lease or unit?

(a) Plans and documents. Before you conduct the activities on your
lease or unit listed in the following table, you must submit, and BSEE
must approve, the listed plans and documents. Your plans and documents
may cover one or more leases or units.

------------------------------------------------------------------------
You must submit a(n) . . . Before you . . .
------------------------------------------------------------------------
(1) [Reserved]
(2) [Reserved]
(3) [Reserved]
(4) Deepwater Operations Plan Conduct post-drilling installation
(DWOP), activities in any water depth
associated with a development
project that will involve the use of
a non-conventional production or
completion technology.
(5) [Reserved]
(6) [Reserved]
------------------------------------------------------------------------

(b) Submitting additional information. On a case-by-case basis, the
Regional Supervisor may require you to submit additional information if
the Regional Supervisor determines that it is necessary to evaluate your
proposed plan or document.
(c) Limiting information. The Regional Director may limit the amount
of information or analyses that you otherwise must provide in your
proposed plan or document under this subpart when:
(1) Sufficient applicable information or analysis is readily
available to BSEE;
(2) Other coastal or marine resources are not present or affected;
(3) Other factors such as technological advances affect information
needs; or
(4) Information is not necessary or required for a State to
determine consistency with their CZMA Plan.
(d) Referencing. In preparing your proposed plan or document, you
may reference information and data discussed in other plans or documents
you previously submitted or that are otherwise readily available to
BSEE.

Sec. Sec. 250.202-250.203 [Reserved]

Sec. 250.204 How must I protect the rights of the Federal government?

(a) To protect the rights of the Federal government, you must
either:
(1) Drill and produce the wells that the Regional Supervisor
determines are necessary to protect the Federal government from loss due
to production on other leases or units or from adjacent lands under the
jurisdiction of other entities (e.g., State and foreign governments); or
(2) Pay a sum that the Regional Supervisor determines as adequate to
compensate the Federal government for your failure to drill and produce
any well.
(b) Payment under paragraph (a)(2) of this section may constitute
production in paying quantities for the purpose of extending the lease
term.
(c) You must complete and produce any penetrated hydrocarbon-bearing
zone that the Regional Supervisor determines is necessary to conform to
sound conservation practices.

Sec. 250.205 Are there special requirements if my well affects
an adjacent property?

For wells that could intersect or drain an adjacent property, the
Regional Supervisor may require special measures to protect the rights
of the Federal government and objecting lessees or operators of adjacent
leases or units.

Post-Approval Requirements for the EP, DPP, and DOCD

Sec. 250.282 Do I have to conduct post-approval monitoring?

The Regional Supervisor may direct you to conduct monitoring
programs. You must retain copies of all monitoring data obtained or
derived from your monitoring programs and make

[[Page 90]]

them available to BSEE upon request. The Regional Supervisor may require
you to:
(a) Monitoring plans. Submit monitoring plans for approval before
you begin work; and
(b) Monitoring reports. Prepare and submit reports that summarize
and analyze data and information obtained or derived from your
monitoring programs. The Regional Supervisor will specify requirements
for preparing and submitting these reports.

Deepwater Operations Plan (DWOP)

Sec. 250.286 What is a DWOP?

(a) A DWOP is a plan that provides sufficient information for BSEE
to review a deepwater development project, and any other project that
uses non-conventional production or completion technology, from a total
system approach. The DWOP does not replace, but supplements other
submittals required by the regulations such as BOEM Exploration Plans,
Development and Production Plans, and Development Operations
Coordination Documents. BSEE will use the information in your DWOP to
determine whether the project will be developed in an acceptable manner,
particularly with respect to operational safety and environmental
protection issues involved with non-conventional production or
completion technology.
(b) The DWOP process consists of two parts: a Conceptual Plan and
the DWOP. Section 250.289 prescribes what the Conceptual Plan must
contain, and Sec. 250.292 prescribes what the DWOP must contain.

Sec. 250.287 For what development projects must I submit a DWOP?

You must submit a DWOP for each development project in which you
will use non-conventional production or completion technology,
regardless of water depth. If you are unsure whether BSEE considers the
technology of your project non-conventional, you must contact the
Regional Supervisor for guidance.

Sec. 250.288 When and how must I submit the Conceptual Plan?

You must submit four copies, or one hard copy and one electronic
version, of the Conceptual Plan to the Regional Director after you have
decided on the general concept(s) for development and before you begin
engineering design of the well safety control system or subsea
production systems to be used after well completion.

Sec. 250.289 What must the Conceptual Plan contain?

In the Conceptual Plan, you must explain the general design basis
and philosophy that you will use to develop the field. You must include
the following information:
(a) An overview of the development concept(s);
(b) A well location plat;
(c) The system control type (i.e., direct hydraulic or electro-
hydraulic); and
(d) The distance from each of the wells to the host platform.

Sec. 250.290 What operations require approval of the Conceptual Plan?

You may not complete any production well or install the subsea
wellhead and well safety control system (often called the tree) before
BSEE has approved the Conceptual Plan.

Sec. 250.291 When and how must I submit the DWOP?

You must submit four copies, or one hard copy and one electronic
version, of the DWOP to the Regional Director after you have
substantially completed safety system design and before you begin to
procure or fabricate the safety and operational systems (other than the
tree), production platforms, pipelines, or other parts of the production
system.

Sec. 250.292 What must the DWOP contain?

You must include the following information in your DWOP:
(a) A description and schematic of the typical wellbore, casing, and
completion;
(b) Structural design, fabrication, and installation information for
each

[[Page 91]]

surface system, including host facilities;
(c) Design, fabrication, and installation information on the mooring
systems for each surface system;
(d) Information on any active stationkeeping system(s) involving
thrusters or other means of propulsion used with a surface system;
(e) Information concerning the drilling and completion systems;
(f) Design and fabrication information for each riser system (e.g.,
drilling, workover, production, and injection);
(g) Pipeline information;
(h) Information about the design, fabrication, and operation of an
offtake system for transferring produced hydrocarbons to a transport
vessel;
(i) Information about subsea wells and associated systems that
constitute all or part of a single project development covered by the
DWOP;
(j) Flow schematics and Safety Analysis Function Evaluation (SAFE)
charts (API RP 14C, subsection 4.3c, incorporated by reference in Sec.
250.198) of the production system from the Surface Controlled Subsurface
Safety Valve (SCSSV) downstream to the first item of separation
equipment;
(k) A description of the surface/subsea safety system and emergency
support systems to include a table that depicts what valves will close,
at what times, and for what events or reasons;
(l) A general description of the operating procedures, including a
table summarizing the curtailment of production and offloading based on
operational considerations;
(m) A description of the facility installation and commissioning
procedure;
(n) A discussion of any new technology that affects hydrocarbon
recovery systems;
(o) A list of any alternate compliance procedures or departures for
which you anticipate requesting approval;
(p) If you propose to use a pipeline free standing hybrid riser
(FSHR) on a permanent installation that utilizes a critical chain, wire
rope, or synthetic tether to connect the top of the riser to a buoyancy
air can, provide the following information in your DWOP in the
discussions required by paragraphs (f) and (g) of this section:
(1) A detailed description and drawings of the FSHR, buoy and the
tether system;
(2) Detailed information on the design, fabrication, and
installation of the FSHR, buoy and tether system, including pressure
ratings, fatigue life, and yield strengths;
(3) A description of how you met the design requirements, load
cases, and allowable stresses for each load case according to API RP 2RD
(as incorporated by reference in Sec. 250.198);
(4) Detailed information regarding the tether system used to connect
the FSHR to a buoyancy air can;
(5) Descriptions of your monitoring system and monitoring plan to
monitor the pipeline FSHR and tether for fatigue, stress, and any other
abnormal condition (e.g., corrosion) that may negatively impact the
riser or tether; and
(6) Documentation that the tether system and connection accessories
for the pipeline FSHR have been certified by an approved classification
society or equivalent and verified by the CVA required in subpart I of
this part; and
(q) Payment of the service fee listed in Sec. 250.125.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 26017, Apr. 29, 2016]

Sec. 250.293 What operations require approval of the DWOP?

You may not begin production until BSEE approves your DWOP.

Sec. 250.294 May I combine the Conceptual Plan and the DWOP?

If your development project meets the following criteria, you may
submit a combined Conceptual Plan/DWOP on or before the deadline for
submitting the Conceptual Plan.
(a) The project is located in water depths of less than 400 meters
(1,312 feet); and
(b) The project is similar to projects involving non-conventional
production or completion technology for which you have obtained approval
previously.

[[Page 92]]

Sec. 250.295 When must I revise my DWOP?

You must revise either the Conceptual Plan or your DWOP to reflect
changes in your development project that materially alter the
facilities, equipment, and systems described in your plan. You must
submit the revision within 60 days after any material change to the
information required for that part of your plan.

Subpart C_Pollution Prevention and Control

Sec. 250.300 Pollution prevention.

(a) During the exploration, development, production, and
transportation of oil and gas or sulphur, the lessee shall take measures
to prevent unauthorized discharge of pollutants into the offshore
waters. The lessee shall not create conditions that will pose
unreasonable risk to public health, life, property, aquatic life,
wildlife, recreation, navigation, commercial fishing, or other uses of
the ocean.
(1) When pollution occurs as a result of operations conducted by or
on behalf of the lessee and the pollution damages or threatens to damage
life (including fish and other aquatic life), property, any mineral
deposits (in areas leased or not leased), or the marine, coastal, or
human environment, the control and removal of the pollution to the
satisfaction of the District Manager shall be at the expense of the
lessee. Immediate corrective action shall be taken in all cases where
pollution has occurred. Corrective action shall be subject to
modification when directed by the District Manager.
(2) If the lessee fails to control and remove the pollution, the
Director, in cooperation with other appropriate Agencies of Federal,
State, and local governments, or in cooperation with the lessee, or
both, shall have the right to control and remove the pollution at the
lessee's expense. Such action shall not relieve the lessee of any
responsibility provided for by law.
(b)(1) The District Manager may restrict the rate of drilling fluid
discharges or prescribe alternative discharge methods. The District
Manager may also restrict the use of components that could cause
unreasonable degradation to the marine environment. No petroleum-based
substances, including diesel fuel, may be added to the drilling mud
system without prior approval of the District Manager. For Arctic OCS
exploratory drilling, you must capture all petroleum-based mud to
prevent its discharge into the marine environment. The Regional
Supervisor may also require you to capture, during your Arctic OCS
exploratory drilling operations, all water-based mud from operations
after completion of the hole for the conductor casing to prevent its
discharge into the marine environment, based on various factors
including, but not limited to:
(i) The proximity of your exploratory drilling operation to
subsistence hunting and fishing locations;
(ii) The extent to which discharged mud may cause marine mammals to
alter their migratory patterns in a manner that impedes subsistence
users' access to, or use of, those resources, or increases the risk of
injury to subsistence users; or
(iii) The extent to which discharged mud may adversely affect marine
mammals, fish, or their habitat.
(2) You must obtain approval from the District Manager of the method
you plan to use to dispose of drill cuttings, sand, and other well
solids. For Arctic OCS exploratory drilling, you must capture all
cuttings from operations that utilize petroleum-based mud to prevent
their discharge into the marine environment. The Regional Supervisor may
also require you to capture, during your Arctic OCS exploratory drilling
operations, all cuttings from operations that utilize water-based mud
after completion of the hole for the conductor casing to prevent their
discharge into the marine environment, based on various factors
including, but not limited to:
(i) The proximity of your exploratory drilling operation to
subsistence hunting and fishing locations;
(ii) The extent to which discharged cuttings may cause marine
mammals to alter their migratory patterns in a manner that impedes
subsistence users' access to, or use of, those resources, or increases
the risk of injury to subsistence users; or

[[Page 93]]

(iii) The extent to which discharged cuttings may adversely affect
marine mammals, fish, or their habitat.
(3) All hydrocarbon-handling equipment for testing and production
such as separators, tanks, and treaters shall be designed, installed,
and operated to prevent pollution. Maintenance or repairs which are
necessary to prevent pollution of offshore waters shall be undertaken
immediately.
(4) Curbs, gutters, drip pans, and drains shall be installed in deck
areas in a manner necessary to collect all contaminants not authorized
for discharge. Oil drainage shall be piped to a properly designed,
operated, and maintained sump system which will automatically maintain
the oil at a level sufficient to prevent discharge of oil into offshore
waters. All gravity drains shall be equipped with a water trap or other
means to prevent gas in the sump system from escaping through the
drains. Sump piles shall not be used as processing devices to treat or
skim liquids but may be used to collect treated-produced water, treated-
produced sand, or liquids from drip pans and deck drains and as a final
trap for hydrocarbon liquids in the event of equipment upsets.
Improperly designed, operated, or maintained sump piles which do not
prevent the discharge of oil into offshore waters shall be replaced or
repaired.
(5) On artificial islands, all vessels containing hydrocarbons shall
be placed inside an impervious berm or otherwise protected to contain
spills. Drainage shall be directed away from the drilling rig to a sump.
Drains and sumps shall be constructed to prevent seepage.
(6) Disposal of equipment, cables, chains, containers, or other
materials into offshore waters is prohibited.
(c) Materials, equipment, tools, containers, and other items used in
the Outer Continental Shelf (OCS) which are of such shape or
configuration that they are likely to snag or damage fishing devices
shall be handled and marked as follows:
(1) All loose material, small tools, and other small objects shall
be kept in a suitable storage area or a marked container when not in use
and in a marked container before transport over offshore waters;
(2) All cable, chain, or wire segments shall be recovered after use
and securely stored until suitable disposal is accomplished;
(3) Skid-mounted equipment, portable containers, spools or reels,
and drums shall be marked with the owner's name prior to use or
transport over offshore waters; and
(4) All markings must clearly identify the owner and must be durable
enough to resist the effects of the environmental conditions to which
they may be exposed.
(d) Any of the items described in paragraph (c) of this section that
are lost overboard shall be recorded on the facility's daily operations
report, as appropriate, and reported to the District Manager.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 46560, July 15, 2016]

Sec. 250.301 Inspection of facilities.

Drilling and production facilities shall be inspected daily or at
intervals approved or prescribed by the District Manager to determine if
pollution is occurring. Necessary maintenance or repairs shall be made
immediately. Records of such inspections and repairs shall be maintained
at the facility or at a nearby manned facility for 2 years.

Subpart D_Oil and Gas Drilling Operations

General Requirements

Sec. 250.400 General requirements.

Drilling operations must be conducted in a safe manner to protect
against harm or damage to life (including fish and other aquatic life),
property, natural resources of the Outer Continental Shelf (OCS),
including any mineral deposits (in areas leased and not leased), the
National security or defense, or the marine, coastal, or human
environment. In addition to the requirements of this subpart, you must
also follow the applicable requirements of subpart G of this part.

[81 FR 26017, Apr. 29, 2016]

[[Page 94]]

Sec. Sec. 250.401-250.403 [Reserved]

Sec. 250.404 What are the requirements for the crown block?

You must have a crown block safety device that prevents the
traveling block from striking the crown block. You must check the device
for proper operation at least once per week and after each drill-line
slipping operation and record the results of this operational check in
the driller's report.

Sec. 250.405 What are the safety requirements for diesel engines
used on a drilling rig?

You must equip each diesel engine with an air intake device to shut
down the diesel engine in the event of a runaway.
(a) For a diesel engine that is not continuously manned, you must
equip the engine with an automatic shutdown device;
(b) For a diesel engine that is continuously manned, you may equip
the engine with either an automatic or remote manual air intake shutdown
device;
(c) You do not have to equip a diesel engine with an air intake
device if it meets one of the following criteria:
(1) Starts a larger engine;
(2) Powers a firewater pump;
(3) Powers an emergency generator;
(4) Powers a BOP accumulator system;
(5) Provides air supply to divers or confined entry personnel;
(6) Powers temporary equipment on a nonproducing platform;
(7) Powers an escape capsule; or
(8) Powers a portable single-cylinder rig washer.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36149, June 6, 2016]

Sec. 250.406 [Reserved]

Sec. 250.407 What tests must I conduct to determine
reservoir characteristics?

You must determine the presence, quantity, quality, and reservoir
characteristics of oil, gas, sulphur, and water in the formations
penetrated by logging, formation sampling, or well testing.

Sec. 250.408 May I use alternative procedures or equipment during
drilling operations?

You may use alternative procedures or equipment during drilling
operations after receiving approval from the District Manager. You must
identify and discuss your proposed alternative procedures or equipment
in your Application for Permit to Drill (APD) (Form BSEE-0123) (see
Sec. 250.414(h)). Procedures for obtaining approval are described in
Sec. 250.141 of this part.

Sec. 250.409 May I obtain departures from these drilling requirements?

The District Manager may approve departures from the drilling
requirements specified in this subpart. You may apply for a departure
from drilling requirements by writing to the District Manager. You
should identify and discuss the departure you are requesting in your APD
(see Sec. 250.414(h)).

Applying for a Permit To Drill

Sec. 250.410 How do I obtain approval to drill a well?

You must obtain written approval from the District Manager before
you begin drilling any well or before you sidetrack, bypass, or deepen a
well. To obtain approval, you must:
(a) Submit the information required by Sec. Sec. 250.411 through
250.418;
(b) Include the well in your approved Exploration Plan (EP),
Development and Production Plan (DPP), or Development Operations
Coordination Document (DOCD);
(c) Meet the oil spill financial responsibility requirements for
offshore facilities as required by 30 CFR part 553; and
(d) Submit the following to the District Manager:
(1) An original and two complete copies of Form BSEE-0123,
Application for Permit to Drill (APD), and Form BSEE-0123S, Supplemental
APD Information Sheet;
(2) A separate public information copy of forms BSEE-0123 and BSEE-
0123S that meets the requirements of Sec. 250.186; and
(3) Payment of the service fee listed in Sec. 250.125.

[[Page 95]]

Sec. 250.411 What information must I submit with my application?

In addition to forms BSEE-0123 and BSEE-0123S, you must include the
information required in this subpart and subpart G of this part,
including the following:

----------------------------------------------------------------------------------------------------------------
Information that you must include with an APD Where to find a description
----------------------------------------------------------------------------------------------------------------
(a) Plat that shows locations of the proposed Sec. 250.412.
well,.
(b) Design criteria used for the proposed well,.. Sec. 250.413.
(c) Drilling prognosis,.......................... Sec. 250.414.
(d) Casing and cementing programs,............... Sec. 250.415.
(e) Diverter systems descriptions,............... Sec. 250.416.
(f) BOP system descriptions,..................... Sec. 250.731.
(g) Requirements for using a MODU, and........... Sec. 250.713.
(h) Additional information....................... Sec. 250.418.
----------------------------------------------------------------------------------------------------------------

[81 FR 26017, Apr. 29, 2016]

Sec. 250.412 What requirements must the location plat meet?

The location plat must:
(a) Have a scale of 1:24,000 (1 inch = 2,000 feet);
(b) Show the surface and subsurface locations of the proposed well
and all the wells in the vicinity;
(c) Show the surface and subsurface locations of the proposed well
in feet or meters from the block line;
(d) Contain the longitude and latitude coordinates, and either
Universal Transverse Mercator grid-system coordinates or state plane
coordinates in the Lambert or Transverse Mercator Projection system for
the surface and subsurface locations of the proposed well; and
(e) State the units and geodetic datum (including whether the datum
is North American Datum 27 or 83) for these coordinates. If the datum
was converted, you must state the method used for this conversion, since
the various methods may produce different values.

Sec. 250.413 What must my description of well drilling design
criteria address?

Your description of well drilling design criteria must address:
(a) Pore pressures;
(b) Formation fracture gradients, adjusted for water depth;
(c) Potential lost circulation zones;
(d) Drilling fluid weights;
(e) Casing setting depths;
(f) Maximum anticipated surface pressures. For this section, maximum
anticipated surface pressures are the pressures that you reasonably
expect to be exerted upon a casing string and its related wellhead
equipment. In calculating maximum anticipated surface pressures, you
must consider: drilling, completion, and producing conditions; drilling
fluid densities to be used below various casing strings; fracture
gradients of the exposed formations; casing setting depths; total well
depth; formation fluid types; safety margins; and other pertinent
conditions. You must include the calculations used to determine the
pressures for the drilling and the completion phases, including the
anticipated surface pressure used for designing the production string;
(g) A single plot containing curves for estimated pore pressures,
formation fracture gradients, proposed drilling fluid weights, planned
safe drilling margin, and casing setting depths in true vertical
measurements;
(h) A summary report of the shallow hazards site survey that
describes the geological and manmade conditions if not previously
submitted; and
(i) Permafrost zones, if applicable.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 26017, Apr. 29, 2016]

Sec. 250.414 What must my drilling prognosis include?

Your drilling prognosis must include a brief description of the
procedures you will follow in drilling the well. This prognosis includes
but is not limited to the following:
(a) Projected plans for coring at specified depths;
(b) Projected plans for logging;
(c) Planned safe drilling margin that is between the estimated pore
pressure and the lesser of estimated fracture

[[Page 96]]

gradients or casing shoe pressure integrity test and that is based on a
risk assessment consistent with expected well conditions and operations.
(1) Your safe drilling margin must also include use of equivalent
downhole mud weight that is:
(i) Greater than the estimated pore pressure; and
(ii) Except as provided in paragraph (c)(2) of this section, a
minimum of 0.5 pound per gallon below the lower of the casing shoe
pressure integrity test or the lowest estimated fracture gradient.
(2) In lieu of meeting the criteria in paragraph (c)(1)(ii) of this
section, you may use an equivalent downhole mud weight as specified in
your APD, provided that you submit adequate documentation (such as risk
modeling data, off-set well data, analog data, seismic data) to justify
the alternative equivalent downhole mud weight.
(3) When determining the pore pressure and lowest estimated fracture
gradient for a specific interval, you must consider related off-set well
behavior observations.
(d) Estimated depths to the top of significant marker formations;
(e) Estimated depths to significant porous and permeable zones
containing fresh water, oil, gas, or abnormally pressured formation
fluids;
(f) Estimated depths to major faults;
(g) Estimated depths of permafrost, if applicable;
(h) A list and description of all requests for using alternate
procedures or departures from the requirements of this subpart in one
place in the APD. You must explain how the alternate procedures afford
an equal or greater degree of protection, safety, or performance, or why
the departures are requested;
(i) Projected plans for well testing (refer to Sec. 250.460);
(j) The type of wellhead system and liner hanger system to be
installed and a descriptive schematic, which includes but is not limited
to pressure ratings, dimensions, valves, load shoulders, and locking
mechanisms, if applicable; and
(k) Any additional information required by the District Manager
needed to clarify or evaluate your drilling prognosis.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 26017, Apr. 29, 2016]

Sec. 250.415 What must my casing and cementing programs include?

Your casing and cementing programs must include:
(a) The following well design information:
(1) Hole sizes;
(2) Bit depths (including measured and true vertical depth (TVD));
(3) Casing information, including sizes, weights, grades, collapse
and burst values, types of connection, and setting depths (measured and
TVD) for all sections of each casing interval; and
(4) Locations of any installed rupture disks (indicate if burst or
collapse and rating);
(b) Casing design safety factors for tension, collapse, and burst
with the assumptions made to arrive at these values;
(c) Type and amount of cement (in cubic feet) planned for each
casing string;
(d) In areas containing permafrost, setting depths for conductor and
surface casing based on the anticipated depth of the permafrost. Your
program must provide protection from thaw subsidence and freezeback
effect, proper anchorage, and well control;
(e) A statement of how you evaluated the best practices included in
API RP 65, Recommended Practice for Cementing Shallow Water Flow Zones
in Deep Water Wells (as incorporated by reference in Sec. 250.198), if
you drill a well in water depths greater than 500 feet and are in either
of the following two areas:
(1) An ``area with an unknown shallow water flow potential'' is a
zone or geologic formation where neither the presence nor absence of
potential for a shallow water flow has been confirmed.
(2) An ``area known to contain a shallow water flow hazard'' is a
zone or geologic formation for which drilling has confirmed the presence
of shallow water flow; and
(f) A written description of how you evaluated the best practices
included in API Standard 65--Part 2, Isolating

[[Page 97]]

Potential Flow Zones During Well Construction, Second Edition (as
incorporated by reference in Sec. 250.198). Your written description
must identify the mechanical barriers and cementing practices you will
use for each casing string (reference API Standard 65--Part 2, Sections
4 and 5).

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50891, Aug. 22, 2012;
81 FR 26018, Apr. 29, 2016]

Sec. 250.416 What must I include in the diverter description?

You must include in the diverter description:
(a) A description of the diverter system and its operating
procedures;
(b) A schematic drawing of the diverter system (plan and elevation
views) that shows:
(1) The size of the element installed in the diverter housing;
(2) Spool outlet internal diameter(s);
(3) Diverter-line lengths and diameters; burst strengths and radius
of curvature at each turn; and
(4) Valve type, size, working pressure rating, and location.

[81 FR 26018, Apr. 29, 2016]

Sec. 250.417 [Reserved]

Sec. 250.418 What additional information must I submit with my APD?

You must include the following with the APD:
(a) Rated capacities of the drilling rig and major drilling
equipment, if not already on file with the appropriate District office;
(b) A drilling fluids program that includes the minimum quantities
of drilling fluids and drilling fluid materials, including weight
materials, to be kept at the site;
(c) A proposed directional plot if the well is to be directionally
drilled;
(d) A Hydrogen Sulfide Contingency Plan (see Sec. 250.490), if
applicable, and not previously submitted;
(e) A welding plan (see Sec. Sec. 250.109 to 250.113) if not
previously submitted;
(f) In areas subject to subfreezing conditions, evidence that the
drilling equipment, BOP systems and components, diverter systems, and
other associated equipment and materials are suitable for operating
under such conditions;
(g) A request for approval, if you plan to wash out or displace
cement to facilitate casing removal upon well abandonment. Your request
must include a description of how far below the mudline you propose to
displace cement and how you will visually monitor returns;
(h) Certification of your casing and cementing program as required
in Sec. 250.420(a)(7); and
(i) Such other information as the District Manager may require.
(j) For Arctic OCS exploratory drilling operations, you must provide
the information required by Sec. 250.470.

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50892, Aug. 22, 2012;
81 FR 26018, Apr. 29, 2016; 81 FR 46561, July 15, 2016]

Casing and Cementing Requirements

Sec. 250.420 What well casing and cementing requirements must I meet?

You must case and cement all wells. Your casing and cementing
programs must meet the applicable requirements of this subpart and of
subpart G of this part.
(a) Casing and cementing program requirements. Your casing and
cementing programs must:
(1) Properly control formation pressures and fluids;
(2) Prevent the direct or indirect release of fluids from any
stratum through the wellbore into offshore waters;
(3) Prevent communication between separate hydrocarbon-bearing
strata;
(4) Protect freshwater aquifers from contamination;
(5) Support unconsolidated sediments;
(6) Provide adequate centralization to ensure proper cementation;
and
(7)(i) Include a certification signed by a registered professional
engineer that the casing and cementing design is appropriate for the
purpose for which it is intended under expected wellbore conditions, and
is sufficient to satisfy the tests and requirements of this section and
Sec. 250.423. Submit this certification with your APD (Form BSEE-0123).

[[Page 98]]

(ii) You must have the registered professional engineer involved in
the casing and cementing design process.
(iii) The registered professional engineer must be registered in a
state of the United States and have sufficient expertise and experience
to perform the certification.
(b) Casing requirements. (1) You must design casing (including
liners) to withstand the anticipated stresses imposed by tensile,
compressive, and buckling loads; burst and collapse pressures; thermal
effects; and combinations thereof.
(2) The casing design must include safety measures that ensure well
control during drilling and safe operations during the life of the well.
(3) On all wells that use subsea BOP stacks, you must include two
independent barriers, including one mechanical barrier, in each annular
flow path (examples of barriers include, but are not limited to, primary
cement job and seal assembly). For the final casing string (or liner if
it is your final string), you must install one mechanical barrier in
addition to cement to prevent flow in the event of a failure in the
cement. A dual float valve, by itself, is not considered a mechanical
barrier. These barriers cannot be modified prior to or during completion
or abandonment operations. The BSEE District Manager may approve
alternative options under Sec. 250.141. You must submit documentation
of this installation to BSEE in the End-of-Operations Report (Form BSEE-
0125).
(4) If you need to substitute a different size, grade, or weight of
casing than what was approved in your APD, you must contact the District
Manager for approval prior to installing the casing.
(c) Cementing requirements. (1) You must design and conduct your
cementing jobs so that cement composition, placement techniques, and
waiting times ensure that the cement placed behind the bottom 500 feet
of casing attains a minimum compressive strength of 500 psi before
drilling out the casing or before commencing completion operations. (If
a liner is used refer to Sec. 250.421(f)).
(2) You must use a weighted fluid during displacement to maintain an
overbalanced hydrostatic pressure during the cement setting time, except
when cementing casings or liners in riserless hole sections.

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50892, Aug. 22, 2012;
81 FR 26018, Apr. 29, 2016]

Sec. 250.421 What are the casing and cementing requirements
by type of casing string?

The table in this section identifies specific design, setting, and
cementing requirements for casing strings and liners. For the purposes
of subpart D, the casing strings in order of normal installation are as
follows: drive or structural, conductor, surface, intermediate, and
production casings (including liners). The District Manager may approve
or prescribe other casing and cementing requirements where appropriate.

------------------------------------------------------------------------
Cementing
Casing type Casing requirements requirements
------------------------------------------------------------------------
(a) Drive or Structural..... Set by driving, If you drilled a
jetting, or portion of this
drilling to the hole, you must use
minimum depth as enough cement to
approved or fill the annular
prescribed by the space back to the
District Manager. mudline.
(b) Conductor............... Design casing and Use enough cement to
select setting fill the calculated
depths based on annular space back
relevant to the mudline.
engineering and Verify annular fill
geologic factors. by observing cement
These factors returns. If you
include the cannot observe
presence or absence cement returns, use
of hydrocarbons, additional cement
potential hazards, to ensure fill-back
and water depths. to the mudline.
Set casing For drilling on an
immediately before artificial island
drilling into or when using a
formations known to well cellar, you
contain oil or gas. must discuss the
If you encounter cement fill level
oil or gas or with the District
unexpected Manager.
formation pressure
before the planned
casing point, you
must set casing
immediately and set
it above the
encountered zone.

[[Page 99]]

(c) Surface................. Design casing and Use enough cement to
select setting fill the calculated
depths based on annular space to at
relevant least 200 feet
engineering and inside the
geologic factors. conductor casing.
These factors When geologic
include the conditions such as
presence or absence near-surface
of hydrocarbons, fractures and
potential hazards, faulting exist, you
and water depths. must use enough
cement to fill the
calculated annular
space to the
mudline.
(d) Intermediate............ Design casing and Use enough cement to
select setting cover and isolate
depth based on all hydrocarbon-
anticipated or bearing zones and
encountered isolate abnormal
geologic pressure intervals
characteristics or from normal
wellbore conditions. pressure intervals
in the well.
As a minimum, you
must cement the
annular space 500
feet above the
casing shoe and 500
feet above each
zone to be
isolated.
(e) Production.............. Design casing and Use enough cement to
select setting cover or isolate
depth based on all hydrocarbon-
anticipated or bearing zones above
encountered the shoe.
geologic As a minimum, you
characteristics or must cement the
wellbore conditions. annular space at
least 500 feet
above the casing
shoe and 500 feet
above the uppermost
hydrocarbon-bearing
zone.
(f) Liners.................. If you use a liner Same as cementing
as surface casing, requirements for
you must set the specific casing
top of the liner at types. For example,
least 200 feet a liner used as
above the previous intermediate casing
casing/liner shoe. must be cemented
If you use a liner according to the
as an intermediate cementing
string below a requirements for
surface string or intermediate
production casing casing. If you have
below an a liner lap and are
intermediate unable to cement
string, you must 500 feet above the
set the top of the previous shoe, as
liner at least 100 provided by
feet above the paragraphs (d) and
previous casing (e) of this
shoe. section, you must
You may not use a submit and receive
liner as conductor approval from the
casing. District Manager on
A subsea well casing a case-by-case
string whose top is basis.
above the mudline
and that has been
cemented back to
the mudline will
not be considered a
liner.
------------------------------------------------------------------------

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 26018, Apr. 29, 2016]

Sec. 250.422 When may I resume drilling after cementing?

(a) After cementing surface, intermediate, or production casing (or
liners), you may resume drilling after the cement has been held under
pressure for 12 hours. For conductor casing, you may resume drilling
after the cement has been held under pressure for 8 hours. One
acceptable method of holding cement under pressure is to use float
valves to hold the cement in place.
(b) If you plan to nipple down your diverter or BOP stack during the
8- or 12-hour waiting time, you must determine, before nippling down,
when it will be safe to do so. You must base your determination on a
knowledge of formation conditions, cement composition, effects of
nippling down, presence of potential drilling hazards, well conditions
during drilling, cementing, and post cementing, as well as past
experience.

Sec. 250.423 What are the requirements for casing and liner installation?

You must ensure proper installation of casing in the subsea wellhead
or liner in the liner hanger.
(a) You must ensure that the latching mechanisms or lock down
mechanisms are engaged upon successfully installing and cementing the
casing string. If there is an indication of an inadequate cement job,
you must comply with Sec. 250.428(c).
(b) If you run a liner that has a latching mechanism or lock down
mechanism, you must ensure that the latching mechanisms or lock down
mechanisms are engaged upon successfully installing and cementing the
liner. If there is an indication of an inadequate cement job, you must
comply with Sec. 250.428(c).
(c) You must perform a pressure test on the casing seal assembly to
ensure proper installation of casing or liner. You must perform this
test for the intermediate and production casing strings or liners.
(1) You must submit for approval with your APD, test procedures and
criteria for a successful test.

[[Page 100]]

(2) You must document all your test results and make them available
to BSEE upon request.

[81 FR 26019, Apr. 29, 2016]

Sec. Sec. 250.424-250.426 [Reserved]

Sec. 250.427 What are the requirements for pressure integrity tests?

You must conduct a pressure integrity test below the surface casing
or liner and all intermediate casings or liners. The District Manager
may require you to run a pressure-integrity test at the conductor casing
shoe if warranted by local geologic conditions or the planned casing
setting depth. You must conduct each pressure integrity test after
drilling at least 10 feet but no more than 50 feet of new hole below the
casing shoe. You must test to either the formation leak-off pressure or
to an equivalent drilling fluid weight if identified in an approved APD.
(a) You must use the pressure integrity test and related hole-
behavior observations, such as pore-pressure test results, gas-cut
drilling fluid, and well kicks to adjust the drilling fluid program and
the setting depth of the next casing string. You must record all test
results and hole-behavior observations made during the course of
drilling related to formation integrity and pore pressure in the
driller's report.
(b) While drilling, you must maintain the safe drilling margins
identified in Sec. 250.414. When you cannot maintain the safe margins,
you must suspend drilling operations and remedy the situation.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 26019, Apr. 29, 2016]

Sec. 250.428 What must I do in certain cementing and casing situations?

The table in this section describes actions that lessees must take
when certain situations occur during casing and cementing activities.

------------------------------------------------------------------------
If you encounter the following situation: Then you must . . .
------------------------------------------------------------------------
(a) Have unexpected formation pressures or Submit a revised casing
conditions that warrant revising your program to the District
casing design, Manager for approval.
(b) Need to change casing setting depths Submit those changes to the
or hole interval drilling depth (for a District Manager for
BHA with an under-reamer, this means bit approval and include a
depth) more than 100 feet true vertical certification by a
depth (TVD) from the approved APD due to professional engineer (PE)
conditions encountered during drilling that he or she reviewed and
operations, approved the proposed
changes.
(c) Have indication of inadequate cement (1) Locate the top of cement
job (such as lost returns, no cement by:
returns to mudline or expected height, (i) Running a temperature
cement channeling, or failure of survey;
equipment), (ii) Running a cement
evaluation log; or
(iii) Using a combination of
these techniques.
(2) Determine if your cement
job is inadequate. If your
cement job is determined to
be inadequate, refer to
paragraph (d) of this
section.
(3) If your cement job is
determined to be adequate,
report the results to the
District Manager in your
submitted WAR.
(d) Inadequate cement job, Take remedial actions. The
District Manager must
review and approve all
remedial actions before you
may take them, unless
immediate actions must be
taken to ensure the safety
of the crew or to prevent a
well-control event. If you
complete any immediate
action to ensure the safety
of the crew or to prevent a
well-control event, submit
a description of the action
to the District Manager
when that action is
complete. Any changes to
the well program will
require submittal of a
certification by a
professional engineer (PE)
certifying that he or she
reviewed and approved the
proposed changes, and must
meet any other requirements
of the District Manager.
(e) Primary cement job that did not Isolate those intervals from
isolate abnormal pressure intervals, normal pressures by squeeze
cementing before you
complete; suspend
operations; or abandon the
well, whichever occurs
first.
(f) Decide to produce a well that was not Have at least two cemented
originally contemplated for production, casing strings (does not
include liners) in the
well. Note: All producing
wells must have at least
two cemented casing
strings.
(g) Want to drill a well without setting Submit geologic data and
conductor casing, information to the District
Manager that demonstrates
the absence of shallow
hydrocarbons or hazards.
This information must
include logging and
drilling fluid-monitoring
from wells previously
drilled within 500 feet of
the proposed well path down
to the next casing point.

[[Page 101]]

(h) Need to use less than required cement Submit information to the
for the surface casing during floating District Manager that
drilling operations to provide protection demonstrates the use of
from burst and collapse pressures, less cement is necessary.
(i) Cement across a permafrost zone, Use cement that sets before
it freezes and has a low
heat of hydration.
(j) Leave the annulus opposite a Fill the annulus with a
permafrost zone uncemented, liquid that has a freezing
point below the minimum
permafrost temperature and
minimizes opposite a
corrosion.
(k) Plan to use a valve(s) on the drive Include a description of the
pipe during cementing operations for the plan in your APD. Your
conductor casing, surface casing, or description must include a
liner, schematic of the valve and
height above the water
line. The valve must be
remotely operated and full
opening with visual
observation while taking
returns. The person in
charge of observing returns
must be in communication
with the drill floor. You
must record in your daily
report and in the WAR if
cement returns were
observed. If cement returns
are not observed, you must
contact the District
Manager and obtain approval
of proposed plans to locate
the top of cement before
continuing with operations.
------------------------------------------------------------------------

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50892, Aug. 22, 2012;
81 FR 26019, Apr. 29, 2016]

Diverter System Requirements

Sec. 250.430 When must I install a diverter system?

You must install a diverter system before you drill a conductor or
surface hole. The diverter system consists of a diverter sealing
element, diverter lines, and control systems. You must design, install,
use, maintain, and test the diverter system to ensure proper diversion
of gases, water, drilling fluid, and other materials away from
facilities and personnel.

Sec. 250.431 What are the diverter design and installation requirements?

You must design and install your diverter system to:
(a) Use diverter spool outlets and diverter lines that have a
nominal diameter of at least 10 inches for surface wellhead
configurations and at least 12 inches for floating drilling operations;
(b) Use dual diverter lines arranged to provide for downwind
diversion capability;
(c) Use at least two diverter control stations. One station must be
on the drilling floor. The other station must be in a readily accessible
location away from the drilling floor;
(d) Use only remote-controlled valves in the diverter lines. All
valves in the diverter system must be full-opening. You may not install
manual or butterfly valves in any part of the diverter system;
(e) Minimize the number of turns (only one 90-degree turn allowed
for each line for bottom-founded drilling units) in the diverter lines,
maximize the radius of curvature of turns, and target all right angles
and sharp turns;
(f) Anchor and support the entire diverter system to prevent
whipping and vibration; and
(g) Protect all diverter-control instruments and lines from possible
damage by thrown or falling objects.

Sec. 250.432 How do I obtain a departure to diverter design
and installation requirements?

The table below describes possible departures from the diverter
requirements and the conditions required for each departure. To obtain
one of these departures, you must have discussed the departure in your
APD and received approval from the District Manager.

------------------------------------------------------------------------
If you want a departure to: Then you must . . .
------------------------------------------------------------------------
(a) Use flexible hose for diverter lines Use flexible hose that has
instead of rigid pipe, integral end couplings.
(b) Use only one spool outlet for your (1) Have branch lines that
diverter system, meet the minimum internal
diameter requirements; and
(2) Provide downwind
diversion capability.
(c) Use a spool with an outlet with an Use a spool that has dual
internal diameter of less than 10 inches outlets with an internal
on a surface wellhead, diameter of at least 8
inches.

[[Page 102]]

(d) Use a single diverter line for Maintain an appropriate
floating drilling operations on a vessel heading to provide
dynamically positioned drillship, for downwind diversion.
------------------------------------------------------------------------

Sec. 250.433 What are the diverter actuation and testing requirements?

When you install the diverter system, you must actuate the diverter
sealing element, diverter valves, and diverter-control systems and
control stations. You must also flow-test the vent lines.
(a) For drilling operations with a surface wellhead configuration,
you must actuate the diverter system at least once every 24-hour period
after the initial test. After you have nippled up on conductor casing,
you must pressure-test the diverter-sealing element and diverter valves
to a minimum of 200 psi. While the diverter is installed, you must
conduct subsequent pressure tests within 7 days after the previous test.
(b) For floating drilling operations with a subsea BOP stack, you
must actuate the diverter system within 7 days after the previous
actuation.
(c) You must alternate actuations and tests between control
stations.

Sec. 250.434 What are the recordkeeping requirements for diverter
actuations and tests?

You must record the time, date, and results of all diverter
actuations and tests in the driller's report. In addition, you must:
(a) Record the diverter pressure test on a pressure chart;
(b) Require your onsite representative to sign and date the pressure
test chart;
(c) Identify the control station used during the test or actuation;
(d) Identify problems or irregularities observed during the testing
or actuations and record actions taken to remedy the problems or
irregularities; and
(e) Retain all pressure charts and reports pertaining to the
diverter tests and actuations at the facility for the duration of
drilling the well.

Sec. Sec. 250.440--250.451 [Reserved]

Sec. 250.452 What are the real-time monitoring requirements
for Arctic OCS exploratory drilling operations?

(a) When conducting exploratory drilling operations on the Arctic
OCS, you must gather and monitor real-time data using an independent,
automatic, and continuous monitoring system capable of recording,
storing, and transmitting data regarding the following:
(1) The BOP control system;
(2) The well's fluid handling systems on the rig; and
(3) The well's downhole conditions as monitored by a downhole
sensing system, when such a system is installed.
(b) During well operations, you must transmit the data identified in
paragraph (a) of this section as they are gathered, barring
unforeseeable or unpreventable interruptions in transmission, and have
the capability to monitor the data onshore, using qualified personnel.
Onshore personnel who monitor real-time data must have the capability to
contact rig personnel during operations. After well operations, you must
store the data at a designated location for recordkeeping purposes as
required in Sec. Sec. 250.740 and 250.741. You must provide BSEE with
access to your real-time monitoring data onshore upon request.

[81 FR 46561, July 15, 2016]

Drilling Fluid Requirements

Sec. 250.455 What are the general requirements for a drilling fluid program?

You must design and implement your drilling fluid program to prevent
the loss of well control. This program must address drilling fluid safe
practices, testing and monitoring equipment, drilling fluid quantities,
and drilling fluid-handling areas.

Sec. 250.456 What safe practices must the drilling fluid program follow?

Your drilling fluid program must include the following safe
practices:

[[Page 103]]

(a) Before starting out of the hole with drill pipe, you must
properly condition the drilling fluid. You must circulate a volume of
drilling fluid equal to the annular volume with the drill pipe just off-
bottom. You may omit this practice if documentation in the driller's
report shows:
(1) No indication of formation fluid influx before starting to pull
the drill pipe from the hole;
(2) The weight of returning drilling fluid is within 0.2 pounds per
gallon (1.5 pounds per cubic foot) of the drilling fluid entering the
hole; and
(3) Other drilling fluid properties are within the limits
established by the program approved in the APD.
(b) Record each time you circulate drilling fluid in the hole in the
driller's report;
(c) When coming out of the hole with drill pipe, you must fill the
annulus with drilling fluid before the hydrostatic pressure decreases by
75 psi, or every five stands of drill pipe, whichever gives a lower
decrease in hydrostatic pressure. You must calculate the number of
stands of drill pipe and drill collars that you may pull before you must
fill the hole. You must also calculate the equivalent drilling fluid
volume needed to fill the hole. Both sets of numbers must be posted near
the driller's station. You must use a mechanical, volumetric, or
electronic device to measure the drilling fluid required to fill the
hole;
(d) You must run and pull drill pipe and downhole tools at
controlled rates so you do not swab or surge the well;
(e) When there is an indication of swabbing or influx of formation
fluids, you must take appropriate measures to control the well. You must
circulate and condition the well, on or near-bottom, unless well or
drilling-fluid conditions prevent running the drill pipe back to the
bottom;
(f) You must calculate and post near the driller's console the
maximum pressures that you may safely contain under a shut-in BOP for
each casing string. The pressures posted must consider the surface
pressure at which the formation at the shoe would break down, the rated
working pressure of the BOP stack, and 70 percent of casing burst (or
casing test as approved by the District Manager). As a minimum, you must
post the following two pressures:
(1) The surface pressure at which the shoe would break down. This
calculation must consider the current drilling fluid weight in the hole;
and
(2) The lesser of the BOP's rated working pressure or 70 percent of
casing-burst pressure (or casing test otherwise approved by the District
Manager);
(g) You must install an operable drilling fluid-gas separator and
degasser before you begin drilling operations. You must maintain this
equipment throughout the drilling of the well;
(h) Before pulling drill-stem test tools from the hole, you must
circulate or reverse-circulate the test fluids in the hole. If
circulating out test fluids is not feasible, you may bullhead test
fluids out of the drill-stem test string and tools with an appropriate
kill weight fluid;
(i) When circulating, you must test the drilling fluid at least once
each tour, or more frequently if conditions warrant. Your tests must
conform to industry-accepted practices and include density, viscosity,
and gel strength; hydrogenion concentration; filtration; and any other
tests the District Manager requires for monitoring and maintaining
drilling fluid quality, prevention of downhole equipment problems and
for kick detection. You must record the results of these tests in the
drilling fluid report; and
(j) In areas where permafrost and/or hydrate zones are present or
may be present, you must control drilling fluid temperatures to drill
safely through those zones.

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50894, Aug. 22, 2012;
81 FR 26020, Apr. 29, 2016]

Sec. 250.457 What equipment is required to monitor drilling fluids?

Once you establish drilling fluid returns, you must install and
maintain the following drilling fluid-system monitoring equipment
throughout subsequent drilling operations. This equipment must have the
following indicators on the rig floor:
(a) Pit level indicator to determine drilling fluid-pit volume gains
and

[[Page 104]]

losses. This indicator must include both a visual and an audible warning
device;
(b) Volume measuring device to accurately determine drilling fluid
volumes required to fill the hole on trips;
(c) Return indicator devices that indicate the relationship between
drilling fluid-return flow rate and pump discharge rate. This indicator
must include both a visual and an audible warning device; and
(d) Gas-detecting equipment to monitor the drilling fluid returns.
The indicator may be located in the drilling fluid-logging compartment
or on the rig floor. If the indicators are only in the logging
compartment, you must continually man the equipment and have a means of
immediate communication with the rig floor. If the indicators are on the
rig floor only, you must install an audible alarm.

Sec. 250.458 What quantities of drilling fluids are required?

(a) You must use, maintain, and replenish quantities of drilling
fluid and drilling fluid materials at the drill site as necessary to
ensure well control. You must determine those quantities based on known
or anticipated drilling conditions, rig storage capacity, weather
conditions, and estimated time for delivery.
(b) You must record the daily inventories of drilling fluid and
drilling fluid materials, including weight materials and additives in
the drilling fluid report.
(c) If you do not have sufficient quantities of drilling fluid and
drilling fluid material to maintain well control, you must suspend
drilling operations.

Sec. 250.459 What are the safety requirements for drilling
fluid-handling areas?

You must classify drilling fluid-handling areas according to API RP
500, Recommended Practice for Classification of Locations for Electrical
Installations at Petroleum Facilities, Classified as Class I, Division 1
and Division 2 (as incorporated by reference in Sec. 250.198); or API
RP 505, Recommended Practice for Classification of Locations for
Electrical Installations at Petroleum Facilities, Classified as Class 1,
Zone 0, Zone 1, and Zone 2 (as incorporated by reference in Sec.
250.198). In areas where dangerous concentrations of combustible gas may
accumulate, you must install and maintain a ventilation system and gas
monitors. Drilling fluid-handling areas must have the following safety
equipment:
(a) A ventilation system capable of replacing the air once every 5
minutes or 1.0 cubic feet of air-volume flow per minute, per square foot
of area, whichever is greater. In addition:
(1) If natural means provide adequate ventilation, then a mechanical
ventilation system is not necessary;
(2) If a mechanical system does not run continuously, then it must
activate when gas detectors indicate the presence of 1 percent or more
of combustible gas by volume; and
(3) If discharges from a mechanical ventilation system may be
hazardous, then you must maintain the drilling fluid-handling area at a
negative pressure. You must protect the negative pressure area by using
at least one of the following: a pressure-sensitive alarm, open-door
alarms on each access to the area, automatic door-closing devices, air
locks, or other devices approved by the District Manager;
(b) Gas detectors and alarms except in open areas where adequate
ventilation is provided by natural means. You must test and recalibrate
gas detectors quarterly. No more than 90 days may elapse between tests;
(c) Explosion-proof or pressurized electrical equipment to prevent
the ignition of explosive gases. Where you use air for pressuring
equipment, you must locate the air intake outside of and as far as
practicable from hazardous areas; and
(d) Alarms that activate when the mechanical ventilation system
fails.

Other Drilling Requirements

Sec. 250.460 What are the requirements for conducting a well test?

(a) If you intend to conduct a well test, you must include your
projected plans for the test with your APD (form BSEE-0123) or in an
Application for Permit to Modify (APM) (form BSEE-0124). Your plans must
include at least the following information:

[[Page 105]]

(1) Estimated flowing and shut-in tubing pressures;
(2) Estimated flow rates and cumulative volumes;
(3) Time duration of flow, buildup, and drawdown periods;
(4) Description and rating of surface and subsurface test equipment;
(5) Schematic drawing, showing the layout of test equipment;
(6) Description of safety equipment, including gas detectors and
fire-fighting equipment;
(7) Proposed methods to handle or transport produced fluids; and
(8) Description of the test procedures.
(b) You must give the District Manager at least 24-hours notice
before starting a well test.

Sec. 250.461 What are the requirements for directional
and inclination surveys?

For this subpart, BSEE classifies a well as vertical if the
calculated average of inclination readings does not exceed 3 degrees
from the vertical.
(a) Survey requirements for a vertical well. (1) You must conduct
inclination surveys on each vertical well and record the results. Survey
intervals may not exceed 1,000 feet during the normal course of
drilling;
(2) You must also conduct a directional survey that provides both
inclination and azimuth, and digitally record the results in electronic
format:
(i) Within 500 feet of setting surface or intermediate casing;
(ii) Within 500 feet of setting any liner; and
(iii) When you reach total depth.
(b) Survey requirements for directional well. You must conduct
directional surveys on each directional well and digitally record the
results. Surveys must give both inclination and azimuth at intervals not
to exceed 500 feet during the normal course of drilling. Intervals
during angle-changing portions of the hole may not exceed 100 feet.
(c) Measurement while drilling. You may use measurement-while-
drilling technology if it meets the requirements of this section.
(d) Composite survey requirements. (1) Your composite directional
survey must show the interval from the bottom of the conductor casing to
total depth. In the absence of conductor casing, the survey must show
the interval from the bottom of the drive or structural casing to total
depth; and
(2) You must correct all surveys to Universal-Transverse-Mercator-
Grid-north or Lambert-Grid-north after making the magnetic-to-true-north
correction. Surveys must show the magnetic and grid corrections used and
include a listing of the directionally computed inclinations and
azimuths.
(e) If you drill within 500 feet of an adjacent lease, the Regional
Supervisor may require you to furnish a copy of the well's directional
survey to the affected leaseholder. This could occur when the adjoining
leaseholder requests a copy of the survey for the protection of
correlative rights.

Sec. 250.462 What are the source control, containment,
and collocated equipment requirements?

For drilling operations using a subsea BOP or surface BOP on a
floating facility, you must have the ability to control or contain a
blowout event at the sea floor.
(a) To determine your required source control and containment
capabilities you must do the following:
(1) Consider a scenario of the wellbore fully evacuated to reservoir
fluids, with no restrictions in the well.
(2) Evaluate the performance of the well as designed to determine if
a full shut-in can be achieved without having reservoir fluids broach to
the sea floor. If your evaluation indicates that the well can only be
partially shut-in, then you must determine your ability to flow and
capture the residual fluids to a surface production and storage system.
(b) You must have access to and the ability to deploy Source Control
and Containment Equipment (SCCE) and all other necessary supporting and
collocated equipment to regain control of the well. SCCE means the
capping stack, cap-and-flow system, containment dome, and/or other
subsea and surface devices, equipment, and vessels, which have the
collective purpose to control a spill source and stop the flow of fluids
into the environment or

[[Page 106]]

to contain fluids escaping into the environment. This SCCE, supporting
equipment, and collocated equipment must include, but is not limited to,
the following:
(1) Subsea containment and capture equipment, including containment
domes and capping stacks;
(2) Subsea utility equipment including hydraulic power sources and
hydrate control equipment;
(3) Collocated equipment including dispersant injection equipment;
(4) Riser systems;
(5) Remotely operated vehicles (ROVs);
(6) Capture vessels;
(7) Support vessels; and
(8) Storage facilities.
(c) You must submit a description of your source control and
containment capabilities to the Regional Supervisor and receive approval
before BSEE will approve your APD, Form BSEE-0123. The description of
your containment capabilities must contain the following:
(1) Your source control and containment capabilities for controlling
and containing a blowout event at the seafloor;
(2) A discussion of the determination required in paragraph (a) of
this section; and
(3) Information showing that you have access to and the ability to
deploy all equipment required by paragraph (b) of this section.
(d) You must contact the District Manager and Regional Supervisor
for reevaluation of your source control and containment capabilities if
your:
(1) Well design changes; or
(2) Approved source control and containment equipment is out of
service.
(e) You must maintain, test, and inspect the source control,
containment, and collocated equipment identified in the following table
according to these requirements:

------------------------------------------------------------------------
Requirements, you Additional
Equipment must: information
------------------------------------------------------------------------
(1) Capping stacks,......... (i) Function test Pressure containing
all pressure critical components
containing critical are those
components on a components that
quarterly frequency will experience
(not to exceed 104 wellbore pressure
days between during a shut-in
tests), after being
functioned.
(ii) Pressure test Pressure containing
pressure containing critical components
critical components are those
on a bi-annual components that
basis, but not will experience
later than 210 days wellbore pressure
from the last during a shut-in.
pressure test. All These components
pressure testing include, but are
must be witnessed not limited to: All
by BSEE (if blind rams,
available) and a wellhead
BSEE-approved connectors, and
verification outlet valves.
organization.
(iii) Notify BSEE at
least 21 days prior
to commencing any
pressure testing.
(2) Production safety (i) Meet or exceed
systems used for flow and the requirements
capture operations, set forth in Sec.
Sec. 250.800
through 250.808,
excluding required
equipment that
would be installed
below the wellhead
or that is not
applicable to the
cap and flow
system.
(ii) Have all
equipment unique to
containment
operations
available for
inspection at all
times.
(3) Subsea utility Have all referenced Subsea utility
equipment,. containment equipment includes,
equipment available but is not limited
for inspection at to: Hydraulic power
all times. sources, debris
removal, and
hydrate control
equipment.
(4) Collocated equipment,... Have equipment Collocated equipment
available for includes, but is
inspection at all not limited to,
times. dispersant
injection equipment
and other subsea
control equipment.
------------------------------------------------------------------------

[81 FR 26020, Apr. 29, 2016]

Sec. 250.463 Who establishes field drilling rules?

(a) The District Manager may establish field drilling rules
different from the requirements of this subpart when geological and
engineering information shows that specific operating requirements are
appropriate. You must comply with field drilling rules and
nonconflicting requirements of this subpart. The District Manager may
amend or cancel field drilling rules at any time.
(b) You may request the District Manager to establish, amend, or
cancel field drilling rules.

[[Page 107]]

Applying for a Permit To Modify and Well Records

Sec. 250.465 When must I submit an Application for Permit to Modify (APM)
or an End of Operations Report to BSEE?

(a) You must submit an APM (form BSEE-0124) or an End of Operations
Report (form BSEE-0125) and other materials to the Regional Supervisor
as shown in the following table. You must also submit a public
information copy of each form.

------------------------------------------------------------------------
When you . . . Then you must . . . And . . .
------------------------------------------------------------------------
(1) Intend to revise Submit form BSEE-0124 Receive written or oral
your drilling plan, or request oral approval from the
change major drilling approval, District Manager before
equipment, or you begin the intended
plugback, operation. If you get an
approval, you must
submit form BSEE-0124 no
later than the end of
the 3rd business day
following the oral
approval. In all cases,
or you must meet the
additional requirements
in paragraph (b) of this
section.
(2) Determine a well's Immediately Submit a Submit a plat certified
final surface form BSEE-0124, by a registered land
location, water surveyor that meets the
depth, and the rotary requirements of Sec.
kelly bushing 250.412.
elevation,
(3) Move a drilling Submit forms BSEE- Submit appropriate copies
unit from a wellbore 0124 and BSEE-0125 of the well records.
before completing a within 30 days after
well, the suspension of
wellbore operations,
------------------------------------------------------------------------

(b) If you intend to perform any of the actions specified in
paragraph (a)(1) of this section, you must meet the following additional
requirements:
(1) Your APM (Form BSEE-0124) must contain a detailed statement of
the proposed work that would materially change from the approved APD.
The submission of your APM must be accompanied by payment of the service
fee listed in Sec. 250.125;
(2) Your form BSEE-0124 must include the present status of the well,
depth of all casing strings set to date, well depth, present production
zones and productive capability, and all other information specified;
and
(3) Within 30 days after completing this work, you must submit an
End of Operations Report (EOR), Form BSEE-0125, as required under Sec.
250.744.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 26021, Apr. 29, 2016]

Sec. Sec. 250.466--250.469 [Reserved]

Additional Arctic OCS Requirements

Source: 81 FR 46561, July 15, 2016, unless otherwise noted.

Sec. 250.470 What additional information must I submit with my APD
for Arctic OCS exploratory drilling operations?

In addition to complying with all other applicable requirements
included in this part, you must provide with your APD all of the
following information pertaining to your proposed Arctic OCS exploratory
drilling:
(a) A detailed description of:
(1) The environmental, meteorological, and oceanic conditions you
expect to encounter at the well site(s);
(2) How you will prepare your equipment, materials, and drilling
unit for service in the conditions identified in paragraph (a)(1) of
this section, and how your drilling unit will be in compliance with the
requirements of Sec. 250.713.
(b) A detailed description of all operations necessary in Arctic OCS
conditions to transition the rig from being under way to conducting
drilling operations and from ending drilling operations to being under
way, as well as any anticipated repair and maintenance plans for the
drilling unit and equipment. You should include, among other things, a
description of how you plan to:
(1) Recover the subsea equipment, including the marine riser and the
lower marine riser package;

[[Page 108]]

(2) Recover the BOP;
(3) Recover the auxiliary sub-sea controls and template;
(4) Lay down the drill pipe and secure the drill pipe and marine
riser;
(5) Secure the drilling equipment;
(6) Transfer the fluids for transport or disposal;
(7) Secure ancillary equipment like the draw works and lines;
(8) Refuel or transfer fuel;
(9) Offload waste;
(10) Recover the Remotely Operated Vehicles;
(11) Pick up the oil spill prevention booms and equipment; and
(12) Offload the drilling crew.
(c) A description of well-specific drilling objectives, timelines,
and updated contingency plans for temporary abandonment of the well,
including but not limited to the following:
(1) When you will spud the particular well (i.e., begin drilling
operations at the well site) identified in the APD;
(2) How long you will take to drill the well;
(3) Anticipated depths and geologic targets, with timelines;
(4) When you expect to set and cement each string of casing;
(5) When and how you would log the well;
(6) Your plans to test the well;
(7) When and how you intend to abandon the well, including
specifically addressing your plans for how to move the rig off location
and how you will meet the requirements of Sec. 250.720(c);
(8) A description of what equipment and vessels will be involved in
the process of temporarily abandoning the well due to ice; and
(9) An explanation of how you will integrate these elements into
your overall program.
(d) A detailed description of your weather and ice forecasting
capability for all phases of the drilling operation, including:
(1) How you will ensure your continuous awareness of potential
weather and ice hazards at, and during transition between, wells;
(2) Your plans for managing ice hazards and responding to weather
events; and
(3) Verification that you have the capabilities described in your
BOEM-approved EP.
(e) A detailed description of how you will comply with the
requirements of Sec. 250.472.
(f) A statement that you own, or have a contract with a provider
for, source control and containment equipment (SCCE), which is capable
of controlling and/or containing a worst case discharge, as described in
your BOEM-approved EP, when proposing to use a MODU to conduct
exploratory drilling operations on the Arctic OCS. The following
information must be included in your SCCE submittal:
(1) A detailed description of your or your contractor's SCCE
capability to stop or contain flow from an out-of-control well,
including your operating assumptions and limitations; your access to and
ability to deploy, in accordance with Sec. 250.471, all necessary SCCE;
and your ability to evaluate the performance of the well design to
determine how you can achieve a full shut-in without having reservoir
fluids discharged into the environment;
(2) An inventory of the local and regional SCCE, supplies, and
services that you own or for which you have a contract with a provider.
You must identify each supplier of such equipment and services and
provide their locations and telephone numbers;
(3) Where applicable, proof of contracts or membership agreements
with cooperatives, service providers, or other contractors who will
provide you with the necessary SCCE or related supplies and services if
you do not possess them. The contract or membership agreement must
include provisions for ensuring the availability of the personnel and/or
equipment on a 24-hour per day basis while you are drilling below or
working below the surface casing;
(4) A detailed description of the procedures you plan to use to
inspect, test, and maintain your SCCE; and
(5) A detailed description of your plan to ensure that all members
of your operating team, who are responsible for operating the SCCE, have
received the necessary training to deploy and operate such equipment in
Arctic

[[Page 109]]

OCS conditions and demonstrate ongoing proficiency in source control
operations. You must also identify and include the dates of prior and
planned training.
(g) Where it does not conflict with other requirements of this
subpart, and except as provided in paragraphs (g)(1) through (11) of
this section, you must comply with the requirements of API RP 2N, Third
Edition ``Planning, Designing, and Constructing Structures and Pipelines
for Arctic Conditions'' (incorporated by reference as specified in Sec.
250.198), and provide a detailed description of how you will utilize the
best practices included in API RP 2N during your exploratory drilling
operations. You are not required to incorporate the following sections
of API RP 2N into your drilling operations:
(1) Sections 6.6.3 through 6.6.4;
(2) The foundation recommendations in Section 8.4;
(3) Section 9.6;
(4) The recommendations for permanently moored systems in Section
9.7;
(5) The recommendations for pile foundations in Section 9.10;
(6) Section 12;
(7) Section 13.2.1;
(8) Sections 13.8.1.1, 13.8.2.1, 13.8.2.2, 13.8.2.4 through
13.8.2.7;
(9) Sections 13.9.1, 13.9.2, 13.9.4 through 13.9.8;
(10) Sections 14 through 16; and
(11) Section 18.

Sec. 250.471 What are the requirements for Arctic OCS source
control and containment?

You must meet the following requirements for all exploration wells
drilled on the Arctic OCS:
(a) If you use a MODU when drilling below or working below the
surface casing, you must have access to the following SCCE capable of
stopping or capturing the flow of an out-of-control well:
(1) A capping stack, positioned to ensure that it will arrive at the
well location within 24 hours after a loss of well control and can be
deployed as directed by the Regional Supervisor pursuant to paragraph
(h) of this section;
(2) A cap and flow system, positioned to ensure that it will arrive
at the well location within 7 days after a loss of well control and can
be deployed as directed by the Regional Supervisor pursuant to paragraph
(h) of this section. The cap and flow system must be designed to capture
at least the amount of hydrocarbons equivalent to the calculated worst
case discharge rate referenced in your BOEM-approved EP; and
(3) A containment dome, positioned to ensure that it will arrive at
the well location within 7 days after a loss of well control and can be
deployed as directed by the Regional Supervisor pursuant to paragraph
(h) of this section. The containment dome must have the capacity to pump
fluids without relying on buoyancy.
(b) You must conduct a monthly stump test of dry-stored capping
stacks. If you use a pre-positioned capping stack, you must conduct a
stump test prior to each installation on each well.
(c) As required by Sec. 250.465(a), if you propose to change your
well design, you must submit an APM. For Arctic OCS operations, your APM
must include a reevaluation of your SCCE capabilities for any new Worst
Case Discharge (WCD) rate, and a demonstration that your SCCE
capabilities will meet the criteria in Sec. 250.470(f) under the
changed well design.
(d) You must conduct tests or exercises of your SCCE, including
deployment of your SCCE, when directed by the Regional Supervisor.
(e) You must maintain records pertaining to testing, inspection, and
maintenance of your SCCE for at least 10 years and make the records
available to any authorized BSEE representative upon request.
(f) You must maintain records pertaining to the use of your SCCE
during testing, training, and deployment activities for at least 3 years
and make the records available to any authorized BSEE representative
upon request.
(g) Upon a loss of well control, you must initiate transit of all
SCCE identified in paragraph (a) of this section to the well.
(h) You must deploy and use SCCE when directed by the Regional
Supervisor.
(i) Operators may request approval of alternate procedures or
equipment to

[[Page 110]]

the SCCE requirements of subparagraph (a) of this section in accordance
with Sec. 250.141. The operator must show and document that the
alternate procedures or equipment will provide a level of safety and
environmental protection that will meet or exceed the level of safety
and environmental protection required by BSEE regulations, including
demonstrating that the alternate procedures or equipment will be capable
of stopping or capturing the flow of an out-of-control well.

Sec. 250.472 What are the relief rig requirements for the Arctic OCS?

(a) In the event of a loss of well control, the Regional Supervisor
may direct you to drill a relief well using the relief rig able to kill
and permanently plug an out-of-control well as described in your APD.
Your relief rig must comply with all other requirements of this part
pertaining to drill rig characteristics and capabilities, and it must be
able to drill a relief well under anticipated Arctic OCS conditions.
(b) When you are drilling below or working below the surface casing
during Arctic OCS exploratory drilling operations, you must have access
to a relief rig, different from your primary drilling rig, staged in a
location such that it can arrive on site, drill a relief well, kill and
abandon the original well, and abandon the relief well prior to expected
seasonal ice encroachment at the drill site, but no later than 45 days
after the loss of well control.
(c) Operators may request approval of alternative compliance
measures to the relief rig requirement in accordance with Sec. 250.141.
The operator must show and document that the alternate compliance
measure will meet or exceed the level of safety and environmental
protection required by BSEE regulations, including demonstrating that
the alternate compliance measure will be able to kill and permanently
plug an out-of-control well.

Sec. 250.473 What must I do to protect health, safety, property,
and theenvironment while operating on the Arctic OCS?

In addition to the requirements set forth in Sec. 250.107, when
conducting exploratory drilling operations on the Arctic OCS, you must
protect health, safety, property, and the environment by using the
following:
(a) Equipment and materials that are rated or de-rated for service
under conditions that can be reasonably expected during your operations;
and
(b) Measures to address human factors associated with weather
conditions that can be reasonably expected during your operations
including, but not limited to, provision of proper attire and equipment,
construction of protected work spaces, and management of shifts.

Hydrogen Sulfide

Sec. 250.490 Hydrogen sulfide.

(a) What precautions must I take when operating in an H2S area? You
must:
(1) Take all necessary and feasible precautions and measures to
protect personnel from the toxic effects of H2S and to
mitigate damage to property and the environment caused by
H2S. You must follow the requirements of this section when
conducting drilling, well-completion/well-workover, and production
operations in zones with H2S present and when conducting
operations in zones where the presence of H2S is unknown. You
do not need to follow these requirements when operating in zones where
the absence of H2S has been confirmed; and
(2) Follow your approved contingency plan.
(b) Definitions. Terms used in this section have the following
meanings:
Facility means a vessel, a structure, or an artificial island used
for drilling, well-completion, well-workover, and/or production
operations.
H2S absent means:
(1) Drilling, logging, coring, testing, or producing operations have
confirmed the absence of H2S in concentrations that could
potentially result in atmospheric concentrations of 20 ppm or more of
H2S; or
(2) Drilling in the surrounding areas and correlation of geological
and seismic data with equivalent stratigraphic units have confirmed an
absence of H2S throughout the area to be drilled.
H2S present means that drilling, logging, coring, testing, or
producing operations have confirmed the presence

[[Page 111]]

of H2S in concentrations and volumes that could potentially
result in atmospheric concentrations of 20 ppm or more of
H2S.
H2S unknown means the designation of a zone or geologic formation
where neither the presence nor absence of H2S has been
confirmed.
Well-control fluid means drilling mud and completion or workover
fluid as appropriate to the particular operation being conducted.
(c) Classifying an area for the presence of H2S. You must:
(1) Request and obtain an approved classification for the area from
the Regional Supervisor before you begin operations. Classifications are
``H2S absent,'' H2S present,'' or ``H2S
unknown'';
(2) Submit your request with your application for permit to drill;
(3) Support your request with available information such as geologic
and geophysical data and correlations, well logs, formation tests, cores
and analysis of formation fluids; and
(4) Submit a request for reclassification of a zone when additional
data indicate a different classification is needed.
(d) What do I do if conditions change? If you encounter
H2S that could potentially result in atmospheric
concentrations of 20 ppm or more in areas not previously classified as
having H2S present, you must immediately notify BSEE and
begin to follow requirements for areas with H2S present.
(e) What are the requirements for conducting simultaneous
operations? When conducting any combination of drilling, well-
completion, well-workover, and production operations simultaneously, you
must follow the requirements in the section applicable to each
individual operation.
(f) Requirements for submitting an H2S Contingency Plan. Before you
begin operations, you must submit an H2S Contingency Plan to
the District Manager for approval. Do not begin operations before the
District Manager approves your plan. You must keep a copy of the
approved plan in the field, and you must follow the plan at all times.
Your plan must include:
(1) Safety procedures and rules that you will follow concerning
equipment, drills, and smoking;
(2) Training you provide for employees, contractors, and visitors;
(3) Job position and title of the person responsible for the overall
safety of personnel;
(4) Other key positions, how these positions fit into your
organization, and what the functions, duties, and responsibilities of
those job positions are;
(5) Actions that you will take when the concentration of
H2S in the atmosphere reaches 20 ppm, who will be responsible
for those actions, and a description of the audible and visual alarms to
be activated;
(6) Briefing areas where personnel will assemble during an H2S
alert. You must have at least two briefing areas on each facility and
use the briefing area that is upwind of the H2S source at any
given time;
(7) Criteria you will use to decide when to evacuate the facility
and procedures you will use to safely evacuate all personnel from the
facility by vessel, capsule, or lifeboat. If you use helicopters during
H2S alerts, describe the types of H2S emergencies
during which you consider the risk of helicopter activity to be
acceptable and the precautions you will take during the flights;
(8) Procedures you will use to safely position all vessels attendant
to the facility. Indicate where you will locate the vessels with respect
to wind direction. Include the distance from the facility and what
procedures you will use to safely relocate the vessels in an emergency;
(9) How you will provide protective-breathing equipment for all
personnel, including contractors and visitors;
(10) The agencies and facilities you will notify in case of a
release of H2S (that constitutes an emergency), how you will
notify them, and their telephone numbers. Include all facilities that
might be exposed to atmospheric concentrations of 20 ppm or more of
H2S;
(11) The medical personnel and facilities you will use if needed,
their addresses, and telephone numbers;
(12) H2S detector locations in production facilities
producing gas containing

[[Page 112]]

20 ppm or more of H2S. Include an ``H2S Detector
Location Drawing'' showing:
(i) All vessels, flare outlets, wellheads, and other equipment
handling production containing H2S;
(ii) Approximate maximum concentration of H2S in the gas
stream; and
(iii) Location of all H2S sensors included in your
contingency plan;
(13) Operational conditions when you expect to flare gas containing
H2S including the estimated maximum gas flow rate,
H2S concentration, and duration of flaring;
(14) Your assessment of the risks to personnel during flaring and
what precautionary measures you will take;
(15) Primary and alternate methods to ignite the flare and
procedures for sustaining ignition and monitoring the status of the
flare (i.e., ignited or extinguished);
(16) Procedures to shut off the gas to the flare in the event the
flare is extinguished;
(17) Portable or fixed sulphur dioxide (SO2)-detection
system(s) you will use to determine SO2 concentration and
exposure hazard when H2S is burned;
(18) Increased monitoring and warning procedures you will take when
the SO2 concentration in the atmosphere reaches 2 ppm;
(19) Personnel protection measures or evacuation procedures you will
initiate when the SO2 concentration in the atmosphere reaches
5 ppm;
(20) Engineering controls to protect personnel from SO2;
and
(21) Any special equipment, procedures, or precautions you will use
if you conduct any combination of drilling, well-completion, well-
workover, and production operations simultaneously.
(g) Training program: (1) When and how often do employees need to be
trained? All operators and contract personnel must complete an
H2S training program to meet the requirements of this
section:
(i) Before beginning work at the facility; and
(ii) Each year, within 1 year after completion of the previous
class.
(2) What training documentation do I need? For each individual
working on the platform, either:
(i) You must have documentation of this training at the facility
where the individual is employed; or
(ii) The employee must carry a training completion card.
(3) What training do I need to give to visitors and employees
previously trained on another facility?
(i) Trained employees or contractors transferred from another
facility must attend a supplemental briefing on your H2S
equipment and procedures before beginning duty at your facility;
(ii) Visitors who will remain on your facility more than 24 hours
must receive the training required for employees by paragraph (g)(4) of
this section; and
(iii) Visitors who will depart before spending 24 hours on the
facility are exempt from the training required for employees, but they
must, upon arrival, complete a briefing that includes:
(A) Information on the location and use of an assigned respirator;
practice in donning and adjusting the assigned respirator; information
on the safe briefing areas, alarm system, and hazards of H2S
and SO2; and
(B) Instructions on their responsibilities in the event of an
H2S release.
(4) What training must I provide to all other employees? You must
train all individuals on your facility on the:
(i) Hazards of H2S and of SO2 and the
provisions for personnel safety contained in the H2S
Contingency Plan;
(ii) Proper use of safety equipment which the employee may be
required to use;
(iii) Location of protective breathing equipment, H2S
detectors and alarms, ventilation equipment, briefing areas, warning
systems, evacuation procedures, and the direction of prevailing winds;
(iv) Restrictions and corrective measures concerning beards,
spectacles, and contact lenses in conformance with ANSI Z88.2, American
National Standard for Respiratory Protection (as specified in Sec.
250.198);
(v) Basic first-aid procedures applicable to victims of
H2S exposure. During all drills and training sessions, you
must address procedures for rescue and first aid for H2S
victims;
(vi) Location of:

[[Page 113]]

(A) The first-aid kit on the facility;
(B) Resuscitators; and
(C) Litter or other device on the facility.
(vii) Meaning of all warning signals.
(5) Do I need to post safety information? You must prominently post
safety information on the facility and on vessels serving the facility
(i.e., basic first-aid, escape routes, instructions for use of life
boats, etc.).
(h) Drills. (1) When and how often do I need to conduct drills on
H2S safety discussions on the facility? You must:
(i) Conduct a drill for each person at the facility during normal
duty hours at least once every 7-day period. The drills must consist of
a dry-run performance of personnel activities related to assigned jobs.
(ii) At a safety meeting or other meetings of all personnel, discuss
drill performance, new H2S considerations at the facility,
and other updated H2S information at least monthly.
(2) What documentation do I need? You must keep records of
attendance for:
(i) Drilling, well-completion, and well-workover operations at the
facility until operations are completed; and
(ii) Production operations at the facility or at the nearest field
office for 1 year.
(i) Visual and audible warning systems: (1) How must I install wind
direction equipment? You must install wind-direction equipment in a
location visible at all times to individuals on or in the immediate
vicinity of the facility.
(2) When do I need to display operational danger signs, display
flags, or activate visual or audible alarms?
(i) You must display warning signs at all times on facilities with
wells capable of producing H2S and on facilities that process
gas containing H2S in concentrations of 20 ppm or more.
(ii) In addition to the signs, you must activate audible alarms and
display flags or activate flashing red lights when atmospheric
concentration of H2S reaches 20 ppm.
(3) What are the requirements for signs? Each sign must be a high-
visibility yellow color with black lettering as follows:

------------------------------------------------------------------------
Letter height Wording
------------------------------------------------------------------------
12 inches................................. Danger.
Poisonous Gas.
Hydrogen Sulfide.
7 inches.................................. Do not approach if red flag
is flying.
(Use appropriate wording at right)........ Do not approach if red
lights are flashing.
------------------------------------------------------------------------

(4) May I use existing signs? You may use existing signs containing
the words ``Danger-Hydrogen Sulfide-H2S,'' provided the words
``Poisonous Gas. Do Not Approach if Red Flag is Flying'' or ``Red Lights
are Flashing'' in lettering of a minimum of 7 inches in height are
displayed on a sign immediately adjacent to the existing sign.
(5) What are the requirements for flashing lights or flags? You must
activate a sufficient number of lights or hoist a sufficient number of
flags to be visible to vessels and aircraft. Each light must be of
sufficient intensity to be seen by approaching vessels or aircraft any
time it is activated (day or night). Each flag must be red, rectangular,
a minimum width of 3 feet, and a minimum height of 2 feet.
(6) What is an audible warning system? An audible warning system is
a public address system or siren, horn, or other similar warning device
with a unique sound used only for H2S.
(7) Are there any other requirements for visual or audible warning
devices? Yes, you must:
(i) Illuminate all signs and flags at night and under conditions of
poor visibility; and
(ii) Use warning devices that are suitable for the electrical
classification of the area.
(8) What actions must I take when the alarms are activated? When the
warning devices are activated, the designated responsible persons must
inform personnel of the level of danger and issue instructions on the
initiation of appropriate protective measures.
(j) H2S-detection and H2S monitoring
equipment: (1) What are the requirements for an H2S detection
system? An H2S detection system must:
(i) Be capable of sensing a minimum of 10 ppm of H2S in
the atmosphere; and
(ii) Activate audible and visual alarms when the concentration of
H2S in the atmosphere reaches 20 ppm.

[[Page 114]]

(2) Where must I have sensors for drilling, well-completion, and
well-workover operations? You must locate sensors at the:
(i) Bell nipple;
(ii) Mud-return line receiver tank (possum belly);
(iii) Pipe-trip tank;
(iv) Shale shaker;
(v) Well-control fluid pit area;
(vi) Driller's station;
(vii) Living quarters; and
(viii) All other areas where H2S may accumulate.
(3) Do I need mud sensors? The District Manager may require mud
sensors in the possum belly in cases where the ambient air sensors in
the mud-return system do not consistently detect the presence of
H2S.
(4) How often must I observe the sensors? During drilling, well-
completion and well-workover operations, you must continuously observe
the H2S levels indicated by the monitors in the work areas
during the following operations:
(i) When you pull a wet string of drill pipe or workover string;
(ii) When circulating bottoms-up after a drilling break;
(iii) During cementing operations;
(iv) During logging operations; and
(v) When circulating to condition mud or other well-control fluid.
(5) Where must I have sensors for production operations? On a
platform where gas containing H2S of 20 ppm or greater is
produced, processed, or otherwise handled:
(i) You must have a sensor in rooms, buildings, deck areas, or low-
laying deck areas not otherwise covered by paragraph (j)(2) of this
section, where atmospheric concentrations of H2S could reach
20 ppm or more. You must have at least one sensor per 400 square feet of
deck area or fractional part of 400 square feet;
(ii) You must have a sensor in buildings where personnel have their
living quarters;
(iii) You must have a sensor within 10 feet of each vessel,
compressor, wellhead, manifold, or pump, which could release enough
H2S to result in atmospheric concentrations of 20 ppm at a
distance of 10 feet from the component;
(iv) You may use one sensor to detect H2S around multiple
pieces of equipment, provided the sensor is located no more than 10 feet
from each piece, except that you need to use at least two sensors to
monitor compressors exceeding 50 horsepower;
(v) You do not need to have sensors near wells that are shut in at
the master valve and sealed closed;
(vi) When you determine where to place sensors, you must consider:
(A) The location of system fittings, flanges, valves, and other
devices subject to leaks to the atmosphere; and
(B) Design factors, such as the type of decking and the location of
fire walls; and
(vii) The District Manager may require additional sensors or other
monitoring capabilities, if warranted by site specific conditions.
(6) How must I functionally test the H2S Detectors? (i) Personnel
trained to calibrate the particular H2S detector equipment
being used must test detectors by exposing them to a known concentration
in the range of 10 to 30 ppm of H2S.
(ii) If the results of any functional test are not within 2 ppm or
10 percent, whichever is greater, of the applied concentration,
recalibrate the instrument.
(7) How often must I test my detectors? (i) When conducting
drilling, drill stem testing, well-completion, or well-workover
operations in areas classified as H2S present or
H2S unknown, test all detectors at least once every 24 hours.
When drilling, begin functional testing before the bit is 1,500 feet
(vertically) above the potential H2S zone.
(ii) When conducting production operations, test all detectors at
least every 14 days between tests.
(iii) If equipment requires calibration as a result of two
consecutive functional tests, the District Manager may require that
H2S-detection and H2S-monitoring equipment be
functionally tested and calibrated more frequently.
(8) What documentation must I keep? (i) You must maintain records of
testing and calibrations (in the drilling or production operations
report, as applicable) at the facility to show the present status and
history of each device, including dates and details concerning:

[[Page 115]]

(A) Installation;
(B) Removal;
(C) Inspection;
(D) Repairs;
(E) Adjustments; and
(F) Reinstallation.
(ii) Records must be available for inspection by BSEE personnel.
(9) What are the requirements for nearby vessels? If vessels are
stationed overnight alongside facilities in areas of H2S
present or H2S unknown, you must equip vessels with an
H2S-detection system that activates audible and visual alarms
when the concentration of H2S in the atmosphere reaches 20
ppm. This requirement does not apply to vessels positioned upwind and at
a safe distance from the facility in accordance with the positioning
procedure described in the approved H2S Contingency Plan.
(10) What are the requirements for nearby facilities? The District
Manager may require you to equip nearby facilities with portable or
fixed H2S detector(s) and to test and calibrate those
detectors. To invoke this requirement, the District Manager will
consider dispersion modeling results from a possible release to
determine if 20 ppm H2S concentration levels could be
exceeded at nearby facilities.
(11) What must I do to protect against SO2 if I burn gas containing
H2S? You must:
(i) Monitor the SO2concentration in the air with portable
or strategically placed fixed devices capable of detecting a minimum of
2 ppm of SO2;
(ii) Take readings at least hourly and at any time personnel detect
SO2 odor or nasal irritation;
(iii) Implement the personnel protective measures specified in the
H2S Contingency Plan if the SO2 concentration in
the work area reaches 2 ppm; and
(iv) Calibrate devices every 3 months if you use fixed or portable
electronic sensing devices to detect SO2.
(12) May I use alternative measures? You may follow alternative
measures instead of those in paragraph (j)(11) of this section if you
propose and the Regional Supervisor approves the alternative measures.
(13) What are the requirements for protective-breathing equipment?
In an area classified as H2S present or H2S
unknown, you must:
(i) Provide all personnel, including contractors and visitors on a
facility, with immediate access to self-contained pressure-demand-type
respirators with hoseline capability and breathing time of at least 15
minutes.
(ii) Design, select, use, and maintain respirators in conformance
with ANSI Z88.2 (as specified in Sec. 250.198).
(iii) Make available at least two voice-transmission devices, which
can be used while wearing a respirator, for use by designated personnel.
(iv) Make spectacle kits available as needed.
(v) Store protective-breathing equipment in a location that is
quickly and easily accessible to all personnel.
(vi) Label all breathing-air bottles as containing breathing-quality
air for human use.
(vii) Ensure that vessels attendant to facilities carry appropriate
protective-breathing equipment for each crew member. The District
Manager may require additional protective-breathing equipment on certain
vessels attendant to the facility.
(viii) During H2S alerts, limit helicopter flights to and
from facilities to the conditions specified in the H2S
Contingency Plan. During authorized flights, the flight crew and
passengers must use pressure-demand-type respirators. You must train all
members of flight crews in the use of the particular type(s) of
respirator equipment made available.
(ix) As appropriate to the particular operation(s), (production,
drilling, well-completion or well-workover operations, or any
combination of them), provide a system of breathing-air manifolds,
hoses, and masks at the facility and the briefing areas. You must
provide a cascade air-bottle system for the breathing-air manifolds to
refill individual protective-breathing apparatus bottles. The cascade
air-bottle system may be recharged by a high-pressure compressor
suitable for providing breathing-quality air, provided the compressor
suction is located in an uncontaminated atmosphere.
(k) Personnel safety equipment: (1) What additional personnel-safety

[[Page 116]]

equipment do I need? You must ensure that your facility has:
(i) Portable H2S detectors capable of detecting a 10 ppm
concentration of H2S in the air available for use by all
personnel;
(ii) Retrieval ropes with safety harnesses to retrieve incapacitated
personnel from contaminated areas;
(iii) Chalkboards and/or note pads for communication purposes
located on the rig floor, shale-shaker area, the cement-pump rooms,
well-bay areas, production processing equipment area, gas compressor
area, and pipeline-pump area;
(iv) Bull horns and flashing lights; and
(v) At least three resuscitators on manned facilities, and a number
equal to the personnel on board, not to exceed three, on normally
unmanned facilities, complete with face masks, oxygen bottles, and spare
oxygen bottles.
(2) What are the requirements for ventilation equipment? You must:
(i) Use only explosion-proof ventilation devices;
(ii) Install ventilation devices in areas where H2S or
SO2 may accumulate; and
(iii) Provide movable ventilation devices in work areas. The movable
ventilation devices must be multidirectional and capable of dispersing
H2S or SO2 vapors away from working personnel.
(3) What other personnel safety equipment do I need? You must have
the following equipment readily available on each facility:
(i) A first-aid kit of appropriate size and content for the number
of personnel on the facility; and
(ii) At least one litter or an equivalent device.
(l) Do I need to notify BSEE in the event of an H2S release? You
must notify BSEE without delay in the event of a gas release which
results in a 15-minute time-weighted average atmospheric concentration
of H2S of 20 ppm or more anywhere on the OCS facility. You
must report these gas releases to the District Manager immediately by
oral communication, with a written follow-up report within 15 days,
pursuant to Sec. Sec. 250.188 through 250.190.
(m) Do I need to use special drilling, completion and workover
fluids or procedures? When working in an area classified as
H2S present or H2S unknown:
(1) You may use either water- or oil-base muds in accordance with
Sec. 250.300(b)(1).
(2) If you use water-base well-control fluids, and if ambient air
sensors detect H2S, you must immediately conduct either the
Garrett-Gas-Train test or a comparable test for soluble sulfides to
confirm the presence of H2S.
(3) If the concentration detected by air sensors in over 20 ppm,
personnel conducting the tests must don protective-breathing equipment
conforming to paragraph (j)(13) of this section.
(4) You must maintain on the facility sufficient quantities of
additives for the control of H2S, well-control fluid pH, and
corrosion equipment.
(i) Scavengers. You must have scavengers for control of
H2S available on the facility. When H2S is
detected, you must add scavengers as needed. You must suspend drilling
until the scavenger is circulated throughout the system.
(ii) Control pH. You must add additives for the control of pH to
water-base well-control fluids in sufficient quantities to maintain pH
of at least 10.0.
(iii) Corrosion inhibitors. You must add additives to the well-
control fluid system as needed for the control of corrosion.
(5) You must degas well-control fluids containing H2S at
the optimum location for the particular facility. You must collect the
gases removed and burn them in a closed flare system conforming to
paragraph (q)(6) of this section.
(n) What must I do in the event of a kick? In the event of a kick,
you must use one of the following alternatives to dispose of the well-
influx fluids giving consideration to personnel safety, possible
environmental damage, and possible facility well-equipment damage:
(1) Contain the well-fluid influx by shutting in the well and
pumping the fluids back into the formation.
(2) Control the kick by using appropriate well-control techniques to
prevent formation fracturing in an open hole within the pressure limits
of the

[[Page 117]]

well equipment (drill pipe, work string, casing, wellhead, BOP system,
and related equipment). The disposal of H2S and other gases
must be through pressurized or atmospheric mud-separator equipment
depending on volume, pressure and concentration of H2S. The
equipment must be designed to recover well-control fluids and burn the
gases separated from the well-control fluid. The well-control fluid must
be treated to neutralize H2S and restore and maintain the
proper quality.
(o) Well testing in a zone known to contain H2S. When testing a well
in a zone with H2S present, you must do all of the following:
(1) Before starting a well test, conduct safety meetings for all
personnel who will be on the facility during the test. At the meetings,
emphasize the use of protective-breathing equipment, first-aid
procedures, and the Contingency Plan. Only competent personnel who are
trained and are knowledgeable of the hazardous effects of H2S
must be engaged in these tests.
(2) Perform well testing with the minimum number of personnel in the
immediate vicinity of the rig floor and with the appropriate test
equipment to safely and adequately perform the test. During the test,
you must continuously monitor H2S levels.
(3) Not burn produced gases except through a flare which meets the
requirements of paragraph (q)(6) of this section. Before flaring gas
containing H2S, you must activate SO2 monitoring
equipment in accordance with paragraph (j)(11) of this section. If you
detect SO2 in excess of 2 ppm, you must implement the
personnel protective measures in your H2S Contingency Plan,
required by paragraph (f) of this section. You must also follow the
requirements of Sec. 250.1164. You must pipe gases from stored test
fluids into the flare outlet and burn them.
(4) Use downhole test tools and wellhead equipment suitable for
H2S service.
(5) Use tubulars suitable for H2S service. You must not
use drill pipe for well testing without the prior approval of the
District Manager. Water cushions must be thoroughly inhibited in order
to prevent H2S attack on metals. You must flush the test
string fluid treated for this purpose after completion of the test.
(6) Use surface test units and related equipment that is designed
for H2S service.
(p) Metallurgical properties of equipment. When operating in a zone
with H2S present, you must use equipment that is constructed
of materials with metallurgical properties that resist or prevent
sulfide stress cracking (also known as hydrogen embrittlement, stress
corrosion cracking, or H2S embrittlement), chloride-stress
cracking, hydrogen-induced cracking, and other failure modes. You must
do all of the following:
(1) Use tubulars and other equipment, casing, tubing, drill pipe,
couplings, flanges, and related equipment that is designed for
H2S service.
(2) Use BOP system components, wellhead, pressure-control equipment,
and related equipment exposed to H2S-bearing fluids in
conformance with NACE Standard MR0175-03 (as specified in Sec.
250.198).
(3) Use temporary downhole well-security devices such as retrievable
packers and bridge plugs that are designed for H2S service.
(4) When producing in zones bearing H2S, use equipment
constructed of materials capable of resisting or preventing sulfide
stress cracking.
(5) Keep the use of welding to a minimum during the installation or
modification of a production facility. Welding must be done in a manner
that ensures resistance to sulfide stress cracking.
(q) General requirements when operating in an H2S zone: (1) Coring
operations. When you conduct coring operations in H2S-bearing
zones, all personnel in the working area must wear protective-breathing
equipment at least 10 stands in advance of retrieving the core barrel.
Cores to be transported must be sealed and marked for the presence of
H2S.
(2) Logging operations. You must treat and condition well-control
fluid in use for logging operations to minimize the effects of
H2S on the logging equipment.
(3) Stripping operations. Personnel must monitor displaced well-
control fluid returns and wear protective-

[[Page 118]]

breathing equipment in the working area when the atmospheric
concentration of H2S reaches 20 ppm or if the well is under
pressure.
(4) Gas-cut well-control fluid or well kick from H2S-bearing zone.
If you decide to circulate out a kick, personnel in the working area
during bottoms-up and extended-kill operations must wear protective-
breathing equipment.
(5) Drill- and workover-string design and precautions. Drill- and
workover-strings must be designed consistent with the anticipated depth,
conditions of the hole, and reservoir environment to be encountered. You
must minimize exposure of the drill- or workover-string to high stresses
as much as practical and consistent with well conditions. Proper
handling techniques must be taken to minimize notching and stress
concentrations. Precautions must be taken to minimize stresses caused by
doglegs, improper stiffness ratios, improper torque, whip, abrasive wear
on tool joints, and joint imbalance.
(6) Flare system. The flare outlet must be of a diameter that allows
easy nonrestricted flow of gas. You must locate flare line outlets on
the downside of the facility and as far from the facility as is
feasible, taking into account the prevailing wind directions, the wake
effects caused by the facility and adjacent structure(s), and the height
of all such facilities and structures. You must equip the flare outlet
with an automatic ignition system including a pilot-light gas source or
an equivalent system. You must have alternate methods for igniting the
flare. You must pipe to the flare system used for H2S all
vents from production process equipment, tanks, relief valves, burst
plates, and similar devices.
(7) Corrosion mitigation. You must use effective means of monitoring
and controlling corrosion caused by acid gases (H2S and
CO2) in both the downhole and surface portions of a
production system. You must take specific corrosion monitoring and
mitigating measures in areas of unusually severe corrosion where
accumulation of water and/or higher concentration of H2S
exists.
(8) Wireline lubricators. Lubricators which may be exposed to fluids
containing H2S must be of H2S-resistant materials.
(9) Fuel and/or instrument gas. You must not use gas containing
H2S for instrument gas. You must not use gas containing
H2S for fuel gas without the prior approval of the District
Manager.
(10) Sensing lines and devices. Metals used for sensing line and
safety-control devices which are necessarily exposed to H2S-
bearing fluids must be constructed of H2S-corrosion resistant
materials or coated so as to resist H2S corrosion.
(11) Elastomer seals. You must use H2S-resistant
materials for all seals which may be exposed to fluids containing
H2S.
(12) Water disposal. If you dispose of produced water by means other
than subsurface injection, you must submit to the District Manager an
analysis of the anticipated H2S content of the water at the
final treatment vessel and at the discharge point. The District Manager
may require that the water be treated for removal of H2S. The
District Manager may require the submittal of an updated analysis if the
water disposal rate or the potential H2S content increases.
(13) Deck drains. You must equip open deck drains with traps or
similar devices to prevent the escape of H2S gas into the
atmosphere.
(14) Sealed voids. You must take precautions to eliminate sealed
spaces in piping designs (e.g., slip-on flanges, reinforcing pads) which
can be invaded by atomic hydrogen when H2S is present.

Subpart E_Oil and Gas Well-Completion Operations

Sec. 250.500 General requirements.

Well-completion operations must be conducted in a manner to protect
against harm or damage to life (including fish and other aquatic life),
property, natural resources of the OCS, including any mineral deposits
(in areas leased and not leased), the National security or defense, or
the marine, coastal, or human environment. In addition to the
requirements of this subpart,

[[Page 119]]

you must also follow the applicable requirements of subpart G of this
part.

[81 FR 26021, Apr. 29, 2016]

Sec. 250.501 Definition.

When used in this subpart, the following term shall have the meaning
given below:
Well-completion operations means the work conducted to establish the
production of a well after the production-casing string has been set,
cemented, and pressure-tested.

Sec. 250.502 [Reserved]

Sec. 250.503 Emergency shutdown system.

When well-completion operations are conducted on a platform where
there are other hydrocarbon-producing wells or other hydrocarbon flow,
an emergency shutdown system (ESD) manually controlled station shall be
installed near the driller's console or well-servicing unit operator's
work station.

Sec. 250.504 Hydrogen sulfide.

When a well-completion operation is conducted in zones known to
contain hydrogen sulfide (H2S) or in zones where the presence
of H2S is unknown (as defined in Sec. 250.490 of this part),
the lessee shall take appropriate precautions to protect life and
property on the platform or completion unit, including, but not limited
to operations such as blowing the well down, dismantling wellhead
equipment and flow lines, circulating the well, swabbing, and pulling
tubing, pumps, and packers. The lessee shall comply with the
requirements in Sec. 250.490 of this part as well as the appropriate
requirements of this subpart.

Sec. 250.505 Subsea completions.

No subsea well completion shall be commenced until the lessee
obtains written approval from the District Manager in accordance with
Sec. 250.513 of this part. That approval shall be based upon a case-by-
case determination that the proposed equipment and procedures will
adequately control the well and permit safe production operations.

Sec. Sec. 250.506-250.508 [Reserved]

Sec. 250.509 Well-completion structures on fixed platforms.

Derricks, masts, substructures, and related equipment shall be
selected, designed, installed, used, and maintained so as to be adequate
for the potential loads and conditions of loading that may be
encountered during the proposed operations. Prior to moving a well-
completion rig or equipment onto a platform, the lessee shall determine
the structural capability of the platform to safely support the
equipment and proposed operations, taking into consideration the
corrosion protection, age of platform, and previous stresses to the
platform.

Sec. 250.510 Diesel engine air intakes.

Diesel engine air intakes must be equipped with a device to shut
down the diesel engine in the event of runaway. Diesel engines that are
continuously attended must be equipped with either remote operated
manual or automatic-shutdown devices. Diesel engines that are not
continuously attended must be equipped with automatic-shutdown devices.

Sec. 250.511 Traveling-block safety device.

All units being used for well-completion operations that have both a
traveling block and a crown block must be equipped with a safety device
that is designed to prevent the traveling block from striking the crown
block. The device must be checked for proper operation weekly and after
each drill-line slipping operation. The results of the operational check
must be entered in the operations log.

Sec. 250.512 Field well-completion rules.

When geological and engineering information available in a field
enables the District Manager to determine specific operating
requirements, field well-completion rules may be established on the
District Manager's initiative or in response to a request from a lessee.
Such rules may modify the specific requirements of this subpart. After
field well-completion rules have been established, well-completion
operations in the field shall be conducted in

[[Page 120]]

accordance with such rules and other requirements of this subpart. Field
well-completion rules may be amended or canceled for cause at any time
upon the initiative of the District Manager or upon the request of a
lessee.

Sec. 250.513 Approval and reporting of well-completion operations.

(a) No well-completion operation may begin until the lessee receives
written approval from the District Manager. If completion is planned and
the data are available at the time you submit the Application for Permit
to Drill and Supplemental APD Information Sheet (Forms BSEE-0123 and
BSEE-0123S), you may request approval for a well-completion on those
forms (see Sec. Sec. 250.410 through 250.418 of this part). If the
District Manager has not approved the completion or if the completion
objective or plans have significantly changed, you must submit an
Application for Permit to Modify (Form BSEE-0124) for approval of such
operations.
(b) You must submit the following with Form BSEE-0124 (or with Form
BSEE-0123; Form BSEE-0123S):
(1) A brief description of the well-completion procedures to be
followed, a statement of the expected surface pressure, and type and
weight of completion fluids;
(2) A schematic drawing of the well showing the proposed producing
zone(s) and the subsurface well-completion equipment to be used;
(3) For multiple completions, a partial electric log showing the
zones proposed for completion, if logs have not been previously
submitted;
(4) All applicable information required in Sec. 250.731.
(5) When the well-completion is in a zone known to contain
H2S or a zone where the presence of H2S is
unknown, information pursuant to Sec. 250.490 of this part; and
(6) Payment of the service fee listed in Sec. 250.125.
(c) Within 30 days after completion, you must submit to the District
Manager an End of Operations Report (Form BSEE-0125), including a
schematic of the tubing and subsurface equipment.
(d) You must submit public information copies of Form BSEE-0125
according to Sec. 250.186.

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50894, Aug. 22, 2012;
81 FR 26021, Apr. 29, 2016]

Sec. 250.514 Well-control fluids, equipment, and operations.

(a) Well-control fluids, equipment, and operations shall be
designed, utilized, maintained, and/or tested as necessary to control
the well in foreseeable conditions and circumstances, including
subfreezing conditions. The well shall be continuously monitored during
well-completion operations and shall not be left unattended at any time
unless the well is shut in and secured.
(b) The following well-control-fluid equipment shall be installed,
maintained, and utilized:
(1) A fill-up line above the uppermost BOP;
(2) A well-control, fluid-volume measuring device for determining
fluid volumes when filling the hole on trips; and
(3) A recording mud-pit-level indicator to determine mud-pit-volume
gains and losses. This indicator shall include both a visual and an
audible warning device.
(c) When coming out of the hole with drill pipe, the annulus shall
be filled with well-control fluid before the change in such fluid level
decreases the hydrostatic pressure 75 pounds per square inch (psi) or
every five stands of drill pipe, whichever gives a lower decrease in
hydrostatic pressure. The number of stands of drill pipe and drill
collars that may be pulled prior to filling the hole and the equivalent
well-control fluid volume shall be calculated and posted near the
operator's station. A mechanical, volumetric, or electronic device for
measuring the amount of well-control fluid required to fill the hole
shall be utilized.

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50894, Aug. 22, 2012;
81 FR 26021, Apr. 29, 2016]

[[Page 121]]

Sec. Sec. 250.515-250.517 [Reserved]

Sec. 250.518 Tubing and wellhead equipment.

(a) No tubing string shall be placed in service or continue to be
used unless such tubing string has the necessary strength and pressure
integrity and is otherwise suitable for its intended use.
(b) When the tree is installed, you must equip wells to monitor for
casing pressure according to the following chart:

------------------------------------------------------------------------
If you . . . you must equip . . . so you can monitor . . .
------------------------------------------------------------------------
(1) fixed platform the wellhead, all annuli (A, B, C, D,
wells, etc., annuli).
(2) subsea wells, the tubing head, the production casing
annulus (A annulus).
(3) hybrid * wells, the surface wellhead, all annuli at the surface
(A and B riser annuli).
If the production casing
below the mudline and
the production casing
riser above the mudline
are pressure isolated
from each other,
provisions must be made
to monitor the
production casing below
the mudline for casing
pressure.
------------------------------------------------------------------------
* Characterized as a well drilled with a subsea wellhead and completed
with a surface casing head, a surface tubing head, a surface tubing
hanger, and a surface christmas tree.

(c) Wellhead, tree, and related equipment shall have a pressure
rating greater than the shut-in tubing pressure and shall be designed,
installed, used, maintained, and tested so as to achieve and maintain
pressure control. New wells completed as flowing or gas-lift wells shall
be equipped with a minimum of one master valve and one surface safety
valve, installed above the master valve, in the vertical run of the
tree.
(d) Subsurface safety equipment must be installed, maintained, and
tested in compliance with the applicable sections in Sec. Sec. 250.810
through 250.839.
(e) When installed, packers and bridge plugs must meet the
following:
(1) All permanently installed packers and bridge plugs must comply
with API Spec. 11D1 (as incorporated by reference in Sec. 250.198);
(2) The production packer must be set at a depth that will allow for
a column of weighted fluids to be placed above the packer that will
exert a hydrostatic force greater than or equal to the force created by
the reservoir pressure below the packer;
(3) The production packer must be set as close as practically
possible to the perforated interval; and
(4) The production packer must be set at a depth that is within the
cemented interval of the selected casing section.
(f) Your APM must include a description and calculations for how you
determined the production packer setting depth.

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012;
81 FR 26021, Apr. 29, 2016; 81 FR 61918, Sept. 7, 2016]

Casing Pressure Management

Sec. 250.519 What are the requirements for casing pressure management?

Once you install your wellhead, you must meet the casing pressure
management requirements of API RP 90 (as incorporated by reference in
Sec. 250.198) and the requirements of Sec. Sec. 250.519 through
250.530. If there is a conflict between API RP 90 and the casing
pressure requirements of this subpart, you must follow the requirements
of this subpart.

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012]

Sec. 250.520 How often do I have to monitor for casing pressure?

You must monitor for casing pressure in your well according to the
following table:

----------------------------------------------------------------------------------------------------------------
with a minimum one pressure data
If you have . . . you must monitor . . . point recorded per . . .
----------------------------------------------------------------------------------------------------------------
(a) fixed platform wells, monthly, month for each casing.

[[Page 122]]

(b) subsea wells, continuously, day for the production casing.
(c) hybrid wells, continuously, day for each riser and/or the
production casing.
(d) wells operating under a casing pressure daily, day for each casing.
request on a manned fixed platform,
(e) wells operating under a casing pressure weekly, week for each casing.
request on an unmanned fixed platform,
----------------------------------------------------------------------------------------------------------------

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012]

Sec. 250.521 When do I have to perform a casing diagnostic test?

(a) You must perform a casing diagnostic test within 30 days after
first observing or imposing casing pressure according to the following
table:

------------------------------------------------------------------------
you must perform a casing
If you have a . . . diagnostic test if . . .
------------------------------------------------------------------------
(1) fixed platform well, the casing pressure is
greater than 100 psig.
(2) subsea well, the measurable casing
pressure is greater than
the external hydrostatic
pressure plus 100 psig
measured at the subsea
wellhead.
(3) hybrid well, a riser or the production
casing pressure is greater
than 100 psig measured at
the surface.
------------------------------------------------------------------------

(b) You are exempt from performing a diagnostic pressure test for
the production casing on a well operating under active gas lift.

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012]

Sec. 250.522 How do I manage the thermal effects caused
by initial production on a newly completed or recompleted well?

A newly completed or recompleted well often has thermal casing
pressure during initial startup. Bleeding casing pressure during the
startup process is considered a normal and necessary operation to manage
thermal casing pressure; therefore, you do not need to evaluate these
operations as a casing diagnostic test. After 30 days of continuous
production, the initial production startup operation is complete and you
must perform casing diagnostic testing as required in Sec. Sec. 250.520
and 250.522.

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012]

Sec. 250.523 When do I have to repeat casing diagnostic testing?

Casing diagnostic testing must be repeated according to the
following table:

------------------------------------------------------------------------
you must repeat diagnostic
When . . . testing . . .
------------------------------------------------------------------------
(a) your casing pressure request approved immediately.
term has expired,
(b) your well, previously on gas lift, has immediately on the
been shut-in or returned to flowing production casing (A
status without gas lift for more than 180 annulus). The production
days, casing (A annulus) of wells
on active gas lift are
exempt from diagnostic
testing.
(c) your casing pressure request becomes within 30 days.
invalid,
(d) a casing or riser has an increase in within 30 days.
pressure greater than 200 psig over the
previous casing diagnostic test,
(e) after any corrective action has been within 30 days.
taken to remediate undesirable casing
pressure, either as a result of a casing
pressure request denial or any other
action,
(f) your fixed platform well production once per year, not to exceed
casing (A annulus) has pressure exceeding 12 months between tests.
10 percent of its minimum internal yield
pressure (MIYP), except for production
casings on active gas lift,
(g) your fixed platform well's outer once every 5 years, at a
casing (B, C, D, etc., annuli) has a minimum.
pressure exceeding 20 percent of its
MIYP,
------------------------------------------------------------------------

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012]

[[Page 123]]

Sec. 250.524 How long do I keep records of casing pressure
and diagnostic tests?

Records of casing pressure and diagnostic tests must be kept at the
field office nearest the well for a minimum of 2 years. The last casing
diagnostic test for each casing or riser must be retained at the field
office nearest the well until the well is abandoned.

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012]

Sec. 250.525 When am I required to take action from
my casing diagnostic test?

You must take action if you have any of the following conditions:
(a) Any fixed platform well with a casing pressure exceeding its
maximum allowable wellhead operating pressure (MAWOP);
(b) Any fixed platform well with a casing pressure that is greater
than 100 psig and that cannot bleed to 0 psig through a \1/2\-inch
needle valve within 24 hours, or is not bled to 0 psig during a casing
diagnostic test;
(c) Any well that has demonstrated tubing/casing, tubing/riser,
casing/casing, riser/casing, or riser/riser communication;
(d) Any well that has sustained casing pressure (SCP) and is bled
down to prevent it from exceeding its MAWOP, except during initial
startup operations described in Sec. 250.521;
(e) Any hybrid well with casing or riser pressure exceeding 100
psig; or
(f) Any subsea well with a casing pressure 100 psig greater than the
external hydrostatic pressure at the subsea wellhead.

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012]

Sec. 250.526 What do I submit if my casing diagnostic test requires action?

Within 14 days after you perform a casing diagnostic test requiring
action under Sec. 250.524:

----------------------------------------------------------------------------------------------------------------
You must submit either . . and it must include . . .
. to the appropriate . . . You must also . . .
----------------------------------------------------------------------------------------------------------------
(a) a notification of District Manager and copy requirements under Sec. submit an Application for
corrective action; or, the Regional Supervisor, 250.526, Permit to Modify or
Field Operations, Corrective Action Plan
within 30 days of the
diagnostic test.
(b) a casing pressure Regional Supervisor, Field requirements under Sec. .............................
request, Operations, 250.527.
----------------------------------------------------------------------------------------------------------------

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012]

Sec. 250.527 What must I include in my notification of corrective action?

The following information must be included in the notification of
corrective action:
(a) Lessee or Operator name;
(b) Area name and OCS block number;
(c) Well name and API number; and
(d) Casing diagnostic test data.

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012]

Sec. 250.528 What must I include in my casing pressure request?

The following information must be included in the casing pressure
request:
(a) API number;
(b) Lease number;
(c) Area name and OCS block number;
(d) Well number;
(e) Company name and mailing address;
(f) All casing, riser, and tubing sizes, weights, grades, and MIYP;
(g) All casing/riser calculated MAWOPs;
(h) All casing/riser pre-bleed down pressures;
(i) Shut-in tubing pressure;
(j) Flowing tubing pressure;
(k) Date and the calculated daily production rate during last well
test (oil, gas, basic sediment, and water);
(l) Well status (shut-in, temporarily abandoned, producing,
injecting, or gas lift);
(m) Well type (dry tree, hybrid, or subsea);

[[Page 124]]

(n) Date of diagnostic test;
(o) Well schematic;
(p) Water depth;
(q) Volumes and types of fluid bled from each casing or riser
evaluated;
(r) Type of diagnostic test performed:
(1) Bleed down/buildup test;
(2) Shut-in the well and monitor the pressure drop test;
(3) Constant production rate and decrease the annular pressure test;
(4) Constant production rate and increase the annular pressure test;
(5) Change the production rate and monitor the casing pressure test;
and
(6) Casing pressure and tubing pressure history plot;
(s) The casing diagnostic test data for all casing exceeding 100
psig;
(t) Associated shoe strengths for casing shoes exposed to annular
fluids;
(u) Concentration of any H2S that may be present;
(v) Whether the structure on which the well is located is manned or
unmanned;
(w) Additional comments; and
(x) Request date.

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012]

Sec. 250.529 What are the terms of my casing pressure request?

Casing pressure requests are approved by the Regional Supervisor,
Field Operations, for a term to be determined by the Regional Supervisor
on a case-by-case basis. The Regional Supervisor may impose additional
restrictions or requirements to allow continued operation of the well.

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012]

Sec. 250.530 What if my casing pressure request is denied?

(a) If your casing pressure request is denied, then the operating
company must submit plans for corrective action to the respective
District Manager within 30 days of receiving the denial. The District
Manager will establish a specific time period in which this corrective
action will be taken. You must notify the respective District Manager
within 30 days after completion of your corrected action.
(b) You must submit the casing diagnostic test data to the
appropriate Regional Supervisor, Field Operations, within 14 days of
completion of the diagnostic test required under Sec. 250.522(e).

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012]

Sec. 250.531 When does my casing pressure request approval become invalid?

A casing pressure request becomes invalid when:
(a) The casing or riser pressure increases by 200 psig over the
approved casing pressure request pressure;
(b) The approved term ends;
(c) The well is worked-over, side-tracked, redrilled, recompleted,
or acid stimulated;
(d) A different casing or riser on the same well requires a casing
pressure request; or
(e) A well has more than one casing operating under a casing
pressure request and one of the casing pressure requests become invalid,
then all casing pressure requests for that well become invalid.

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012]

Subpart F_Oil and Gas Well-Workover Operations

Sec. 250.600 General requirements.

Well-workover operations must be conducted in a manner to protect
against harm or damage to life (including fish and other aquatic life),
property, natural resources of the Outer Continental Shelf (OCS)
including any mineral deposits (in areas leased and not leased), the
National security or defense, or the marine, coastal, or human
environment. In addition to the requirements of this subpart, you must
also follow the applicable requirements of subpart G of this part.

[81 FR 26021, Apr. 29, 2016]

Sec. 250.601 Definitions.

When used in this subpart, the following terms shall have the
meanings given below:
Expected surface pressure means the highest pressure predicted to be
exerted upon the surface of a well. In calculating expected surface
pressure, you

[[Page 125]]

must consider reservoir pressure as well as applied surface pressure.
Routine operations mean any of the following operations conducted on
a well with the tree installed:
(a) Cutting paraffin;
(b) Removing and setting pump-through-type tubing plugs, gas-lift
valves, and subsurface safety valves which can be removed by wireline
operations;
(c) Bailing sand;
(d) Pressure surveys;
(e) Swabbing;
(f) Scale or corrosion treatment;
(g) Caliper and gauge surveys;
(h) Corrosion inhibitor treatment;
(i) Removing or replacing subsurface pumps;
(j) Through-tubing logging (diagnostics);
(k) Wireline fishing; and
(l) Setting and retrieving other subsurface flow-control devices.
Workover operations mean the work conducted on wells after the
initial completion for the purpose of maintaining or restoring the
productivity of a well.

Sec. 250.602 [Reserved]

Sec. 250.603 Emergency shutdown system.

When well-workover operations are conducted on a well with the tree
removed, an emergency shutdown system (ESD) manually controlled station
shall be installed near the driller's console or well-servicing unit
operator's work station, except when there is no other hydrocarbon-
producing well or other hydrocarbon flow on the platform.

Sec. 250.604 Hydrogen sulfide.

When a well-workover operation is conducted in zones known to
contain hydrogen sulfide (H2S) or in zones where the presence
of H2S is unknown (as defined in Sec. 250.490 of this part),
the lessee shall take appropriate precautions to protect life and
property on the platform or rig, including but not limited to operations
such as blowing the well down, dismantling wellhead equipment and flow
lines, circulating the well, swabbing, and pulling tubing, pumps and
packers. The lessee shall comply with the requirements in Sec. 250.490
of this part as well as the appropriate requirements of this subpart.

Sec. 250.605 Subsea workovers.

No subsea well-workover operation including routine operations shall
be commenced until the lessee obtains written approval from the District
Manager in accordance with Sec. 250.613 of this part. That approval
shall be based upon a case-by-case determination that the proposed
equipment and procedures will maintain adequate control of the well and
permit continued safe production operations.

Sec. Sec. 250.606-250.608 [Reserved]

Sec. 250.609 Well-workover structures on fixed platforms.

Derricks, masts, substructures, and related equipment shall be
selected, designed, installed, used, and maintained so as to be adequate
for the potential loads and conditions of loading that may be
encountered during the operations proposed. Prior to moving a well-
workover rig or well-servicing equipment onto a platform, the lessee
shall determine the structural capability of the platform to safely
support the equipment and proposed operations, taking into consideration
the corrosion protection, age of the platform, and previous stresses to
the platform.

Sec. 250.610 Diesel engine air intakes.

You must equip diesel engine air intakes with a device to shut down
the diesel engine in the event of runaway. Diesel engines that are
continuously attended must be equipped with remotely operated, manual,
or automatic shutdown devices. Diesel engines that are not continuously
attended must be equipped with automatic shutdown devices.

[81 FR 36149, June 6, 2016]

Sec. 250.611 Traveling-block safety device.

You must equip all units being used for well-workover operations
that have both a traveling block and a crown block with a safety device
that is designed to prevent the traveling block from striking the crown
block. You

[[Page 126]]

must check the device for proper operation weekly and after each drill-
line slipping operation. You must enter the results of the operational
check in the operations log.

[81 FR 36149, June 6, 2016]

Sec. 250.612 Field well-workover rules.

When geological and engineering information available in a field
enables the District Manager to determine specific operating
requirements, field well-workover rules may be established on the
District Manager's initiative or in response to a request from a lessee.
Such rules may modify the specific requirements of this subpart. After
field well-workover rules have been established, well-workover
operations in the field shall be conducted in accordance with such rules
and other requirements of this subpart. Field well-workover rules may be
amended or canceled for cause at any time upon the initiative of the
District Manager or upon the request of a lessee.

Sec. 250.613 Approval and reporting for well-workover operations.

(a) No well-workover operation except routine ones, as defined in
Sec. 250.601 of this part, shall begin until the lessee receives
written approval from the District Manager. Approval for these
operations must be requested on Form BSEE-0124, Application for Permit
to Modify.
(b) You must submit the following with Form BSEE-0124:
(1) A brief description of the well-workover procedures to be
followed, a statement of the expected surface pressure, and type and
weight of workover fluids;
(2) When changes in existing subsurface equipment are proposed, a
schematic drawing of the well showing the zone proposed for workover and
the workover equipment to be used;
(3) All information required in Sec. 250.731.
(4) Where the well-workover is in a zone known to contain
H2S or a zone where the presence of H2S is unknown,
information pursuant to Sec. 250.490 of this part; and
(5) Payment of the service fee listed in Sec. 250.125.
(c) The following additional information shall be submitted with
Form BSEE-0124 if completing to a new zone is proposed:
(1) Reason for abandonment of present producing zone including
supportive well test data, and
(2) A statement of anticipated or known pressure data for the new
zone.
(d) Within 30 days after completing the well-workover operation,
except routine operations, Form BSEE-0124, Application for Permit to
Modify, shall be submitted to the District Manager, showing the work as
performed. In the case of a well-workover operation resulting in the
initial recompletion of a well into a new zone, a Form BSEE-0125, End of
Operations Report, shall be submitted to the District Manager and shall
include a new schematic of the tubing subsurface equipment if any
subsurface equipment has been changed.

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50895, Aug. 22, 2012;
81 FR 26021, Apr. 29, 2016]

Sec. 250.614 Well-control fluids, equipment, and operations.

The following requirements apply during all well-workover operations
with the tree removed:
(a) Well-control fluids, equipment, and operations shall be
designed, utilized, maintained, and/or tested as necessary to control
the well in foreseeable conditions and circumstances, including
subfreezing conditions. The well shall be continuously monitored during
well-workover operations and shall not be left unattended at anytime
unless the well is shut in and secured.
(b) When coming out of the hole with drill pipe or a workover
string, the annulus shall be filled with well-control fluid before the
change in such fluid level decreases the hydrostatic pressure 75 pounds
per square inch (psi) or every five stands of drill pipe or workover
string, whichever gives a lower decrease in hydrostatic pressure. The
number of stands of drill pipe or workover string and drill collars that
may be pulled prior to filling the hole and the equivalent well-control
fluid volume shall be calculated and posted near the operator's station.
A mechanical, volumetric, or electronic device

[[Page 127]]

for measuring the amount of well-control fluid required to fill the hold
shall be utilized.
(c) The following well-control-fluid equipment shall be installed,
maintained, and utilized:
(1) A fill-up line above the uppermost BOP;
(2) A well-control, fluid-volume measuring device for determining
fluid volumes when filling the hole on trips; and
(3) A recording mud-pit-level indicator to determine mud-pit-volume
gains and losses. This indicator shall include both a visual and an
audible warning device.

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50895, Aug. 22, 2012;
81 FR 26021, Apr. 29, 2016]

Sec. 250.615 [Reserved]

Sec. 250.616 Coiled tubing and snubbing operations.

(a) For coiled tubing operations with the production tree in place,
you must meet the following minimum requirements for the BOP system:
(1) BOP system components must be in the following order from the
top down:

------------------------------------------------------------------------
BOP system when
BOP system when expected expected surface BOP system for wells
surface pressures are less pressures are with returns taken
than or equal to 3,500 psi greater than 3,500 through an outlet on
psi the BOP stack
------------------------------------------------------------------------
Stripper or annular-type Stripper or annular- Stripper or annular-
well control component. type well control type well control
component. component.
Hydraulically-operated blind Hydraulically- Hydraulically-
rams. operated blind rams. operated blind rams
Hydraulically-operated shear Hydraulically- Hydraulically-
rams. operated shear rams. operated shear
rams.
Kill line inlet............. Kill line inlet..... Kill line inlet.
Hydraulically-operated two- Hydraulically- Hydraulically-
way slip rams. operated two-way operated two-way
slip rams. slip rams.
Hydraulically-
operated pipe rams.
Hydraulically-operated pipe Hydraulically- A flow tee or cross.
rams. operated pipe rams. Hydraulically-
Hydraulically- operated pipe rams.
operated blind- Hydraulically-
shear rams. These operated blind-
rams should be shear rams on wells
located as close to with surface
the tree as pressures 3,500 psi. As an
option, the pipe
rams can be placed
below the blind-
shear rams. The
blind-shear rams
should be located
as close to the
tree as practical.
------------------------------------------------------------------------

[[Page 128]]

charge pressure, without assistance from a charging system.
(7) All connections used in the surface BOP system from the tree to
the uppermost required ram must be flanged, including the connections
between the well control stack and the first full-opening valve on the
choke line and the kill line.
(b) The minimum BOP-system components for well-workover operations
with the tree in place and performed by moving tubing or drill pipe in
or out of a well under pressure utilizing equipment specifically
designed for that purpose, i.e., snubbing operations, shall include the
following:
(1) One set of pipe rams hydraulically operated, and
(2) Two sets of stripper-type pipe rams hydraulically operated with
spacer spool.
(c) An inside BOP or a spring-loaded, back-pressure safety valve and
an essentially full-opening, work-string safety valve in the open
position shall be maintained on the rig floor at all times during well-
workover operations when the tree is removed or during well-workover
operations with the tree installed and using small tubing as the work
string. A wrench to fit the work-string safety valve shall be readily
available. Proper connections shall be readily available for inserting
valves in the work string. The full-opening safety valve is not required
for coiled tubing or snubbing operations.

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50895, Aug. 22, 2012,
as amended at 81 FR 26021, Apr. 29, 2016]

Sec. Sec. 250.617-250.618 [Reserved]

Sec. 250.619 Tubing and wellhead equipment.

The lessee shall comply with the following requirements during well-
workover operations with the tree removed:
(a) No tubing string shall be placed in service or continue to be
used unless such tubing string has the necessary strength and pressure
integrity and is otherwise suitable for its intended use.
(b) When reinstalling the tree, you must:
(1) Equip wells to monitor for casing pressure according to the
following chart:

------------------------------------------------------------------------
If you have . . . you must equip . . . so you can monitor . . .
------------------------------------------------------------------------
(i) fixed platform the wellhead, all annuli (A, B, C, D,
wells, etc., annuli).
(ii) subsea wells, the tubing head, the production casing
annulus (A annulus).
(iii) hybrid* wells, the surface wellhead, all annuli at the surface
(A and B riser annuli).
If the production casing
below the mudline and
the production casing
riser above the mudline
are pressure isolated
from each other,
provisions must be made
to monitor the
production casing below
the mudline for casing
pressure.
------------------------------------------------------------------------
* Characterized as a well drilled with a subsea wellhead and completed
with a surface casing head, a surface tubing head, a surface tubing
hanger, and a surface christmas tree.

(2) Follow the casing pressure management requirements in subpart E
of this part.
(c) Wellhead, tree, and related equipment shall have a pressure
rating greater than the shut-in tubing pressure and shall be designed,
installed, used, maintained, and tested so as to achieve and maintain
pressure control. The tree shall be equipped with a minimum of one
master valve and one surface safety valve in the vertical run of the
tree when it is reinstalled.
(d) Subsurface safety equipment must be installed, maintained, and
tested in compliance with the applicable sections in Sec. Sec. 250.810
through 250.839.
(e) If you pull and reinstall packers and bridge plugs, you must
meet the following requirements:
(1) All permanently installed packers and bridge plugs must comply
with API Spec. 11D1 (as incorporated by reference in Sec. 250.198);
(2) The production packer must be set at a depth that will allow for
a column of weighted fluids to be placed above the packer that will
exert a hydrostatic force greater than or equal to the force created by
the reservoir pressure below the packer;
(3) The production packer must be set as close as practically
possible to the perforated interval; and

[[Page 129]]

(4) The production packer must be set at a depth that is within the
cemented interval of the selected casing section.
(f) Your APM must include a description and calculations for how you
determined the production packer setting depth.

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50895, Aug. 22, 2012,
as amended at 81 FR 26021, Apr. 29, 2016; 81 FR 61918, Sept. 7, 2016]

Sec. 250.620 Wireline operations.

The lessee shall comply with the following requirements during
routine, as defined in Sec. 250.601 of this part, and nonroutine
wireline workover operations:
(a) Wireline operations shall be conducted so as to minimize leakage
of well fluids. Any leakage that does occur shall be contained to
prevent pollution.
(b) All wireline perforating operations and all other wireline
operations where communication exists between the completed hydrocarbon-
bearing zone(s) and the wellbore shall use a lubricator assembly
containing at least one wireline valve.
(c) When the lubricator is initially installed on the well, it shall
be successfully pressure tested to the expected shut-in surface
pressure.

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50895, Aug. 22, 2012]

Subpart G_Well Operations and Equipment

Source: 81 FR 26022, Apr. 29, 2016, unless otherwise noted.

General Requirements

Sec. 250.700 What operations and equipment does this subpart cover?

This subpart covers operations and equipment associated with
drilling, completion, workover, and decommissioning activities. This
subpart includes regulations applicable to drilling, completion,
workover, and decommissioning activities in addition to applicable
regulations contained in subparts D, E, F, and Q of this part unless
explicitly stated otherwise.

Sec. 250.701 May I use alternate procedures or equipment during operations?

You may use alternate procedures or equipment during operations
after receiving approval as described in Sec. 250.141. You must
identify and discuss your proposed alternate procedures or equipment in
your Application for Permit to Drill (APD) (Form BSEE-0123) (see Sec.
250.414(h)) or your Application for Permit to Modify (APM) (Form BSEE-
0124). Procedures for obtaining approval of alternate procedures or
equipment are described in Sec. 250.141.

Sec. 250.702 May I obtain departures from these requirements?

You may apply for a departure from these requirements as described
in Sec. 250.142. Your request must include a justification showing why
the departure is necessary. You must identify and discuss the departure
you are requesting in your APD (see Sec. 250.414(h)) or your APM.

Sec. 250.703 What must I do to keep wells under control?

You must take the necessary precautions to keep wells under control
at all times, including:
(a) Use recognized engineering practices to reduce risks to the
lowest level practicable when monitoring and evaluating well conditions
and to minimize the potential for the well to flow or kick;
(b) Have a person onsite during operations who represents your
interests and can fulfill your responsibilities;
(c) Ensure that the toolpusher, operator's representative, or a
member of the rig crew maintains continuous surveillance on the rig
floor from the beginning of operations until the well is completed or
abandoned, unless you have secured the well with blowout preventers
(BOPs), bridge plugs, cement plugs, or packers;
(d) Use personnel trained according to the provisions of subparts O
and S of this part;
(e) Use and maintain equipment and materials necessary to ensure the
safety and protection of personnel, equipment, natural resources, and
the environment; and

[[Page 130]]

(f) Use equipment that has been designed, tested, and rated for the
maximum environmental and operational conditions to which it may be
exposed while in service.

Rig Requirements

Sec. 250.710 What instructions must be given to personnel engaged
in well operations?

Prior to engaging in well operations, personnel must be instructed
in:
(a) Hazards and safety requirements. You must instruct your
personnel regarding the safety requirements for the operations to be
performed, possible hazards to be encountered, and general safety
considerations to protect personnel, equipment, and the environment as
required by subpart S of this part. The date and time of safety meetings
must be recorded and available at the facility for review by BSEE
representatives.
(b) Well control. You must prepare a well-control plan for each
well. Each well-control plan must contain instructions for personnel
about the use of each well-control component of your BOP, procedures
that describe how personnel will seal the wellbore and shear pipe before
maximum anticipated surface pressure (MASP) conditions are exceeded,
assignments for each crew member, and a schedule for completion of each
assignment. You must keep a copy of your well-control plan on the rig at
all times, and make it available to BSEE upon request. You must post a
copy of the well-control plan on the rig floor.

Sec. 250.711 What are the requirements for well-control drills?

You must conduct a weekly well-control drill with all personnel
engaged in well operations. Your drill must familiarize personnel
engaged in well operations with their roles and functions so that they
can perform their duties promptly and efficiently as outlined in the
well-control plan required by Sec. 250.710.
(a) Timing of drills. You must conduct each drill during a period of
activity that minimizes the risk to operations. The timing of your
drills must cover a range of different operations, including drilling
with a diverter, on-bottom drilling, and tripping. The same drill may
not be repeated consecutively with the same crew.
(b) Recordkeeping requirements. For each drill, you must record the
following in the daily report:
(1) Date, time, and type of drill conducted;
(2) The amount of time it took to be ready to close the diverter or
use each well-control component of BOP system; and
(3) The total time to complete the entire drill.
(c) A BSEE ordered drill. A BSEE representative may require you to
conduct a well-control drill during a BSEE inspection. The BSEE
representative will consult with your onsite representative before
requiring the drill.

Sec. 250.712 What rig unit movements must I report?

(a) You must report the movement of all rig units on and off
locations to the District Manager using Form BSEE-0144, Rig Movement
Notification Report. Rig units include MODUs, platform rigs, snubbing
units, wire-line units used for non-routine operations, and coiled
tubing units. You must inform the District Manager 24 hours before:
(1) The arrival of a rig unit on location;
(2) The movement of a rig unit to another slot. For movements that
will occur less than 24 hours after initially moving onto location
(e.g., coiled tubing and batch operations), you may include your
anticipated movement schedule on Form BSEE-0144; or
(3) The departure of a rig unit from the location.
(b) You must provide the District Manager with the rig name, lease
number, well number, and expected time of arrival or departure.
(c) If a MODU or platform rig is to be warm or cold stacked, you
must inform the District Manager:
(1) Where the MODU or platform rig is coming from;
(2) The location where the MODU or platform rig will be positioned;
(3) Whether the MODU or platform rig will be manned or unmanned; and
(4) If the location for stacking the MODU or platform rig changes.

[[Page 131]]

(d) Prior to resuming operations after stacking, you must notify the
appropriate District Manager of any construction, repairs, or
modifications associated with the drilling package made to the MODU or
platform rig.
(e) If a drilling rig is entering OCS waters, you must inform the
District Manager where the drilling rig is coming from.
(f) If you change your anticipated date for initially moving on or
off location by more than 24 hours, you must submit an updated Form
BSEE-0144, Rig Movement Notification Report.

Sec. 250.713 What must I provide if I plan to use a mobile offshore
drilling unit (MODU) for well operations?

If you plan to use a MODU for well operations, you must provide:
(a) Fitness requirements. Information and data to demonstrate the
MODU's capability to perform at the proposed location. This information
must include the maximum environmental and operational conditions that
the MODU is designed to withstand, including the minimum air gap
necessary for both hurricane and non-hurricane seasons. If sufficient
environmental information and data are not available at the time you
submit your APD or APM, the District Manager may approve your APD or
APM, but require you to collect and report this information during
operations. Under this circumstance, the District Manager may revoke the
approval of the APD or APM if information collected during operations
shows that the MODU is not capable of performing at the proposed
location.
(b) Foundation requirements. Information to show that site-specific
soil and oceanographic conditions are capable of supporting the proposed
bottom-founded MODU. If you provided sufficient site-specific
information in your EP, DPP, or DOCD submitted to BOEM for that well
location and conditions, you may reference that information. The
District Manager may require you to conduct additional surveys and soil
borings before approving the APD or APM if additional information is
needed to make a determination that the conditions are capable of
supporting the MODU, or equipment installed on a subsea wellhead. For a
moored rig, you must submit a plat of the rig's anchor pattern approved
in your EP, DPP, or DOCD in your APD or APM.
(c) For frontier areas. (1) If the design of the MODU you plan to
use in a frontier area is unique or has not been proven for use in the
proposed environment, the District Manager may require you to submit a
third-party review of the MODU design. If required, you must obtain a
third-party review of your MODU similar to the process outlined in
Sec. Sec. 250.915 through 250.918. You may submit this information
before submitting an APD or APM.
(2) If you plan to conduct operations in a frontier area, you must
have a contingency plan that addresses design and operating limitations
of the MODU. Your plan must identify the actions necessary to maintain
safety and prevent damage to the environment. Actions must include the
suspension, curtailment, or modification of operations to remedy various
operational or environmental situations (e.g., vessel motion, riser
offset, anchor tensions, wind speed, wave height, currents, icing or
ice-loading, settling, tilt or lateral movement, resupply capability).
(d) Additional documentation. You must provide the current
Certificate of Inspection (for U.S.-flag vessels) or Certificate of
Compliance (for foreign-flag vessels) from the USCG and Certificate of
Classification. You must also provide current documentation of any
operational limitations imposed by an appropriate classification
society.
(e) Dynamically positioned MODU. If you use a dynamically positioned
MODU, you must include in your APD or APM your contingency plan for
moving off location in an emergency situation. At a minimum, your plan
must address emergency events caused by storms, currents, station-
keeping failures, power failures, and losses of well control. The
District Manager may require your plan to include additional events that
may require movement of the MODU and other information needed to clarify
or further address how the MODU will respond to emergencies or other
events.
(f) Inspection of MODU. The MODU must be available for inspection by
the District Manager before commencing

[[Page 132]]

operations and at any time during operations.
(g) Current monitoring. For water depths greater than 400 meters
(1,312 feet), you must include in your APD or APM:
(1) A description of the specific current speeds that will cause you
to implement rig shutdown, move-off procedures, or both; and
(2) A discussion of the specific measures you will take to curtail
rig operations and move off location when such currents are encountered.
You may use criteria, such as current velocities, riser angles, watch
circles, and remaining rig power to describe when these procedures or
measures will be implemented.

[81 FR 26022, Apr. 29, 2016, as amended at 81 FR 36150, June 6, 2016]

Sec. 250.714 Do I have to develop a dropped objects plan?

If you use a floating rig unit in an area with subsea
infrastructure, you must develop a dropped objects plan and make it
available to BSEE upon request. This plan must be updated as the
infrastructure on the seafloor changes. Your plan must include:
(a) A description and plot of the path the rig will take while
running and pulling the riser;
(b) A plat showing the location of any subsea wells, production
equipment, pipelines, and any other identified debris;
(c) Modeling of a dropped object's path with consideration given to
metocean conditions for various material forms, such as a tubular (e.g.,
riser or casing) and box (e.g., BOP or tree);
(d) Communications, procedures, and delegated authorities
established with the production host facility to shut-in any active
subsea wells, equipment, or pipelines in the event of a dropped object;
and
(e) Any additional information required by the District Manager as
appropriate to clarify, update, or evaluate your dropped objects plan.

Sec. 250.715 Do I need a global positioning system (GPS) for all MODUs?

All MODUs must have a minimum of two functioning GPS transponders at
all times, and you must provide to BSEE real-time access to the GPS data
prior to and during each hurricane season.
(a) The GPS must be capable of monitoring the position and tracking
the path in real-time if the MODU moves from its location during a
severe storm.
(b) You must install and protect the tracking system's equipment to
minimize the risk of the system being disabled.
(c) You must place the GPS transponders in different locations for
redundancy to minimize risk of system failure.
(d) Each GPS transponder must be capable of transmitting data for at
least 7 days after a storm has passed.
(e) If the MODU is moved off location in the event of a storm, you
must immediately begin to record the GPS location data.
(f) You must contact the Regional Office and allow real-time access
to the MODU location data. When you contact the Regional Office, provide
the following:
(1) Name of the lessee and operator with contact information;
(2) MODU name;
(3) Initial date and time; and
(4) How you will provide GPS real-time access.

Well Operations

Sec. 250.720 When and how must I secure a well?

(a) Whenever you interrupt operations, you must notify the District
Manager. Before moving off the well, you must have two independent
barriers installed, at least one of which must be a mechanical barrier,
as approved by the District Manager. You must install the barriers at
appropriate depths within a properly cemented casing string or liner.
Before removing a subsea BOP stack or surface BOP stack on a mudline
suspension well, you must conduct a negative pressure test in accordance
with Sec. 250.721.
(1) The events that would cause you to interrupt operations and
notify the District Manager include, but are not limited to, the
following:
(i) Evacuation of the rig crew;

[[Page 133]]

(ii) Inability to keep the rig on location;
(iii) Repair to major rig or well-control equipment; or
(iv) Observed flow outside the well's casing (e.g., shallow water
flow or bubbling).
(2) The District Manager may approve alternate procedures or
barriers, in accordance with Sec. 250.141, if you do not have time to
install the required barriers or if special circumstances occur.
(b) Before you displace kill-weight fluid from the wellbore and/or
riser, thereby creating an underbalanced state, you must obtain approval
from the District Manager. To obtain approval, you must submit with your
APD or APM your reasons for displacing the kill-weight fluid and provide
detailed step-by-step written procedures describing how you will safely
displace these fluids. The step-by-step displacement procedures must
address the following:
(1) Number and type of independent barriers, as described in Sec.
250.420(b)(3), that are in place for each flow path that requires such
barriers;
(2) Tests you will conduct to ensure integrity of independent
barriers;
(3) BOP procedures you will use while displacing kill-weight fluids;
and
(4) Procedures you will use to monitor the volumes and rates of
fluids entering and leaving the wellbore.
(c) For Arctic OCS exploratory drilling operations, in addition to
the requirements of paragraphs (a) and (b) of this section:
(1) If you move your drilling rig off a well prior to completion or
permanent abandonment, you must ensure that any equipment left on, near,
or in a wellbore that has penetrated below the surface casing is
positioned in a manner to:
(i) Protect the well head; and
(ii) Prevent or minimize the likelihood of compromising the down-
hole integrity of the well or the effectiveness of the well plugs.
(2) In areas of ice scour you must use a well mudline cellar or an
equivalent means of minimizing the risk of damage to the well head and
wellbore. BSEE may approve an equivalent means that will meet or exceed
the level of safety and environmental protection provided by a mudline
cellar if the operator can show that utilizing a mudline cellar would
compromise the stability of the rig, impede access to the well head
during a well control event, or otherwise create operational risks.

[81 FR 26022, Apr. 29, 2016, as amended at 81 FR 46563, July 15, 2016]

Sec. 250.721 What are the requirements for pressure testing
casing and liners?

(a) You must test each casing string that extends to the wellhead
according to the following table:

------------------------------------------------------------------------
Casing type Minimum test pressure
------------------------------------------------------------------------
(1) Drive or Structural,............... Not required.
(2) Conductor, excluding subsea 250 psi.
wellheads,.
(3) Surface, Intermediate, and 70 percent of its minimum
Production,. internal yield.
------------------------------------------------------------------------

(b) You must test each drilling liner and liner-top to a pressure at
least equal to the anticipated leak-off pressure of the formation below
that liner shoe, or subsequent liner shoes if set. You must conduct this
test before you continue operations in the well.
(c) You must test each production liner and liner-top to a minimum
of 500 psi above the formation fracture pressure at the casing shoe into
which the liner is lapped.
(d) The District Manager may approve or require other casing test
pressures as appropriate under the circumstances to ensure casing
integrity.
(e) If you plan to produce a well, you must:
(1) For a well that is fully cased and cemented, pressure test the
entire well to maximum anticipated shut-in tubing pressure, not to
exceed 70% of the burst rating limit of the weakest component before
perforating the casing or liner; or

[[Page 134]]

(2) For an open-hole completion, pressure test the entire well to
maximum anticipated shut-in tubing pressure, not to exceed 70% of the
burst rating limit of the weakest component before you drill the open-
hole section.
(f) You may not resume operations until you obtain a satisfactory
pressure test. If the pressure declines more than 10 percent in a 30-
minute test, or if there is another indication of a leak, you must
submit to the District Manager for approval your proposed plans to re-
cement, repair the casing or liner, or run additional casing/liner to
provide a proper seal. Your submittal must include a PE certification of
your proposed plans.
(g) You must perform a negative pressure test on all wells that use
a subsea BOP stack or wells with mudline suspension systems.
(1) You must perform a negative pressure test on your final casing
string or liner. This test must be conducted after setting your second
barrier just above the shoe track, but prior to conducting any
completion operations.
(2) You must perform a negative pressure test prior to unlatching
the BOP at any point in the well. The negative pressure test must be
performed on those components, at a minimum, that will be exposed to the
negative differential pressure that will occur when the BOP is
disconnected.
(3) The District Manager may require you to perform additional
negative pressure tests on other casing strings or liners (e.g.,
intermediate casing string or liner) or on wells with a surface BOP
stack as appropriate to demonstrate casing or liner integrity.
(4) You must submit for approval with your APD or APM, test
procedures and criteria for a successful negative pressure test. If any
of your test procedures or criteria for a successful test change, you
must submit for approval the changes in a revised APD or APM.
(5) You must document all your test results and make them available
to BSEE upon request.
(6) If you have any indication of a failed negative pressure test,
such as, but not limited to, pressure buildup or observed flow, you must
immediately investigate the cause. If your investigation confirms that a
failure occurred during the negative pressure test, you must:
(i) Correct the problem and immediately notify the appropriate
District Manager; and
(ii) Submit a description of the corrective action taken and receive
approval from the appropriate District Manager for the retest.
(7) You must have two barriers in place, as described in Sec.
250.420(b)(3), at any time and for any well, prior to performing the
negative pressure test.
(8) You must include documentation of the successful negative
pressure test in the End-of-Operations Report (Form BSEE-0125).

Sec. 250.722 What are the requirements for prolonged operations in a well?

If wellbore operations continue within a casing or liner for more
than 30 days from the previous pressure test of the well's casing or
liner, you must:
(a) Stop operations as soon as practicable, and evaluate the effects
of the prolonged operations on continued operations and the life of the
well. At a minimum, you must:
(1) Evaluate the well casing with a pressure test, caliper tool, or
imaging tool. On a case-by-case basis, the District Manager may require
a specific method of evaluation of the effects on the well casing of
prolonged operations; and
(2) Report the results of your evaluation to the District Manager
and obtain approval of those results before resuming operations. Your
report must include calculations that show the well's integrity is above
the minimum safety factors, if an imaging tool or caliper is used.
(b) If well integrity has deteriorated to a level below minimum
safety factors, you must:
(1) Obtain approval from the District Manager to begin repairs or
install additional casing. To obtain approval, you must also provide a
PE certification showing that he or she reviewed and approved the
proposed changes;
(2) Repair the casing or run another casing string; and
(3) Perform a pressure test after the repairs are made or additional
casing is installed and report the results to the

[[Page 135]]

District Manager as specified in Sec. 250.721.

Sec. 250.723 What additional safety measures must I take when I conduct
operations on a platform that has producing wells or has
other hydrocarbon flow?

You must take the following safety measures when you conduct
operations with a rig unit or lift boat on or jacked-up over a platform
with producing wells or that has other hydrocarbon flow:
(a) The movement of rig units and related equipment on and off a
platform or from well to well on the same platform, including rigging up
and rigging down, must be conducted in a safe manner;
(b) You must install an emergency shutdown station for the
production system near the rig operator's console;
(c) You must shut-in all producible wells located in the affected
wellbay below the surface and at the wellhead when:
(1) You move a rig unit or related equipment on and off a platform.
This includes rigging up and rigging down activities within 500 feet of
the affected platform;
(2) You move or skid a rig unit between wells on a platform; or
(3) A MODU or lift boat moves within 500 feet of a platform. You may
resume production once the MODU or lift boat is in place, secured, and
ready to begin operations.
(d) All wells in the same well-bay which are capable of producing
hydrocarbons must be shut-in below the surface with a pump-through-type
tubing plug and at the surface with a closed master valve prior to
moving rig units and related equipment, unless otherwise approved by the
District Manager.
(1) A closed surface-controlled subsurface safety valve of the pump-
through-type may be used in lieu of the pump-through-type tubing plug
provided that the surface control has been locked out of operation.
(2) The well to which a rig unit or related equipment is to be moved
must be equipped with a back-pressure valve prior to removing the tree
and installing and testing the BOP system.
(3) The well from which a rig unit or related equipment is to be
moved must be equipped with a back pressure valve prior to removing the
BOP system and installing the production tree.
(e) Coiled tubing units, snubbing units, or wireline units may be
moved onto and off of a platform without shutting in wells.

Sec. 250.724 What are the real-time monitoring requirements?

(a) No later than April 29, 2019, when conducting well operations
with a subsea BOP or with a surface BOP on a floating facility, or when
operating in an high pressure high temperature (HPHT) environment, you
must gather and monitor real-time well data using an independent,
automatic, and continuous monitoring system capable of recording,
storing, and transmitting data regarding the following:
(1) The BOP control system;
(2) The well's fluid handling system on the rig; and
(3) The well's downhole conditions with the bottom hole assembly
tools (if any tools are installed).
(b) You must transmit these data as they are gathered, barring
unforeseeable or unpreventable interruptions in transmission, and have
the capability to monitor the data onshore, using qualified personnel in
accordance with a real-time monitoring plan, as provided in paragraph
(c) of this section. Onshore personnel who monitor real-time data must
have the capability to contact rig personnel during operations. After
operations, you must preserve and store these data onshore for
recordkeeping purposes as required in Sec. Sec. 250.740 and 250.741.
You must provide BSEE with access to your designated real-time
monitoring data onshore upon request. You must include in your APD a
certification that you have a real-time monitoring plan that meets the
criteria in paragraph (c) of this section.
(c) You must develop and implement a real-time monitoring plan. Your
real-time monitoring plan, and all real-time monitoring data, must be
made available to BSEE upon request. Your real-time monitoring plan must
include the following:
(1) A description of your real-time monitoring capabilities,
including the types of the data collected;

[[Page 136]]

(2) A description of how your real-time monitoring data will be
transmitted onshore during operations, how the data will be labeled and
monitored by qualified onshore personnel, and how it will be stored
onshore;
(3) A description of your procedures for providing BSEE access, upon
request, to your real-time monitoring data including, if applicable, the
location of any onshore data monitoring or data storage facilities;
(4) The qualifications of the onshore personnel monitoring the data;
(5) Your procedures for, and methods of, communication between rig
personnel and the onshore monitoring personnel; and
(6) Actions to be taken if you lose any real-time monitoring
capabilities or communications between rig and onshore personnel, and a
protocol for how you will respond to any significant and/or prolonged
interruption of monitoring or onshore-offshore communications, including
your protocol for notifying BSEE of any significant and/or prolonged
interruptions.

Blowout Preventer (BOP) System Requirements

Sec. 250.730 What are the general requirements for BOP systems
and system components?

(a) You must ensure that the BOP system and system components are
designed, installed, maintained, inspected, tested, and used properly to
ensure well control. The working-pressure rating of each BOP component
(excluding annular(s)) must exceed MASP as defined for the operation.
For a subsea BOP, the MASP must be taken at the mudline. The BOP system
includes the BOP stack, control system, and any other associated
system(s) and equipment. The BOP system and individual components must
be able to perform their expected functions and be compatible with each
other. Your BOP system (excluding casing shear) must be capable of
closing and sealing the wellbore at all times, including under
anticipated flowing conditions for the specific well conditions, without
losing ram closure time and sealing integrity due to the corrosiveness,
volume, and abrasiveness of any fluids in the wellbore that the BOP
system may encounter. Your BOP system must meet the following
requirements:
(1) The BOP requirements of API Standard 53 (incorporated by
reference in Sec. 250.198) and the requirements of Sec. Sec. 250.733
through 250.739. If there is a conflict between API Standard 53, and the
requirements of this subpart, you must follow the requirements of this
subpart.
(2) Those provisions of the following industry standards (all
incorporated by reference in Sec. 250.198) that apply to BOP systems:
(i) ANSI/API Spec. 6A;
(ii) ANSI/API Spec. 16A;
(iii) ANSI/API Spec. 16C;
(iv) API Spec. 16D; and
(v) ANSI/API Spec. 17D.
(3) For surface and subsea BOPs, the pipe and variable bore rams
installed in the BOP stack must be capable of effectively closing and
sealing on the tubular body of any drill pipe, workstring, and tubing
(excluding tubing with exterior control lines and flat packs) in the
hole under MASP, as defined for the operation, with the proposed
regulator settings of the BOP control system.
(4) The current set of approved schematic drawings must be available
on the rig and at an onshore location. If you make any modifications to
the BOP or control system that will change your BSEE-approved schematic
drawings, you must suspend operations until you obtain approval from the
District Manager.
(b) You must ensure that the design, fabrication, maintenance, and
repair of your BOP system is in accordance with the requirements
contained in this part, Original Equipment Manufacturers (OEM)
recommendations unless otherwise directed by BSEE, and recognized
engineering practices. The training and qualification of repair and
maintenance personnel must meet or exceed any OEM training
recommendations unless otherwise directed by BSEE.
(c) You must follow the failure reporting procedures contained in
API Standard 53, ANSI/API Spec. 6A, and ANSI/API Spec 16A (all
incorporated by reference in Sec. 250.198), and:

[[Page 137]]

(1) You must provide a written notice of equipment failure to the
Chief, Office of Offshore Regulatory Programs, and the manufacturer of
such equipment within 30 days after the discovery and identification of
the failure. A failure is any condition that prevents the equipment from
meeting the functional specification.
(2) You must ensure that an investigation and a failure analysis are
performed within 120 days of the failure to determine the cause of the
failure. You must also ensure that the results and any corrective action
are documented. If the investigation and analysis are performed by an
entity other than the manufacturer, you must ensure that the Chief,
Office of Offshore Regulatory Programs and the manufacturer receive a
copy of the analysis report.
(3) If the equipment manufacturer notifies you that it has changed
the design of the equipment that failed or if you have changed operating
or repair procedures as a result of a failure, then you must, within 30
days of such changes, report the design change or modified procedures in
writing to the Chief, Office of Offshore Regulatory Programs.
(4) You must send the reports required in this paragraph to: Chief,
Office of Offshore Regulatory Programs; Bureau of Safety and
Environmental Enforcement; 45600 Woodland Road, Sterling, VA 20166.
(d) If you plan to use a BOP stack manufactured after the effective
date of this regulation, you must use one manufactured pursuant to an
API Spec. Q1 (as incorporated by reference in Sec. 250.198) quality
management system. Such quality management system must be certified by
an entity that meets the requirements of ISO 17011.
(1) BSEE may consider accepting equipment manufactured under quality
assurance programs other than API Spec. Q1, provided you submit a
request to the Chief, Office of Offshore Regulatory Programs for
approval, containing relevant information about the alternative program.
(2) You must submit this request to the Chief, Office of Offshore
Regulatory Programs; Bureau of Safety and Environmental Enforcement;
45600 Woodland Road, Sterling, Virginia 20166.

Sec. 250.731 What information must I submit for BOP systems
and system components?

For any operation that requires the use of a BOP, you must include
the information listed in this section with your applicable APD, APM, or
other submittal. You are required to submit this information only once
for each well, unless the information changes from what you provided in
an earlier approved submission or you have moved off location from the
well. After you have submitted this information for a particular well,
subsequent APMs or other submittals for the well should reference the
approved submittal containing the information required by this section
and confirm that the information remains accurate and that you have not
moved off location from that well. If the information changes or you
have moved off location from the well, you must submit updated
information in your next submission.

------------------------------------------------------------------------
You must submit: Including:
------------------------------------------------------------------------
(a) A complete description of the (1) Pressure ratings of BOP
BOP system and system components, equipment;
(2) Proposed BOP test pressures (for
subsea BOPs, include both surface
and corresponding subsea
pressures);
(3) Rated capacities for liquid and
gas for the fluid-gas separator
system;
(4) Control fluid volumes needed to
close, seal, and open each
component;
(5) Control system pressure and
regulator settings needed to
achieve an effective seal of each
ram BOP under MASP as defined for
the operation;
(6) Number and volume of accumulator
bottles and bottle banks (for
subsea BOP, include both surface
and subsea bottles);
(7) Accumulator pre-charge
calculations (for subsea BOP,
include both surface and subsea
calculations);
(8) All locking devices; and
(9) Control fluid volume
calculations for the accumulator
system (for a subsea BOP system,
include both the surface and subsea
volumes).
(b) Schematic drawings,........... (1) The inside diameter of the BOP
stack;
(2) Number and type of preventers
(including blade type for shear
ram(s));

[[Page 138]]

(3) All locking devices;
(4) Size range for variable bore
ram(s);
(5) Size of fixed ram(s);
(6) All control systems with all
alarms and set points labeled,
including pods;
(7) Location and size of choke and
kill lines (and gas bleed line(s)
for subsea BOP);
(8) Associated valves of the BOP
system;
(9) Control station locations; and
(10) A cross-section of the riser
for a subsea BOP system showing
number, size, and labeling of all
control, supply, choke, and kill
lines down to the BOP.
(c) Certification by a BSEE- Verification that:
approved verification (1) Test data demonstrate the shear
organization (BAVO), ram(s) will shear the drill pipe at
the water depth as required in Sec.
250.732;
(2) The BOP was designed, tested,
and maintained to perform under the
maximum environmental and
operational conditions anticipated
to occur at the well; and
(3) The accumulator system has
sufficient fluid to operate the BOP
system without assistance from the
charging system.
(d) Additional certification by a Verification that:
BAVO, if you use a subsea BOP, a (1) The BOP stack is designed and
BOP in an HPHT environment as suitable for the specific equipment
defined in Sec. 250.807, or a on the rig and for the specific
surface BOP on a floating well design;
facility, (2) The BOP stack has not been
compromised or damaged from
previous service; and
(3) The BOP stack will operate in
the conditions in which it will be
used.
(e) If you are using a subsea BOP, A listing of the functions with
descriptions of autoshear, their sequences and timing.
deadman, and emergency disconnect
sequence (EDS) systems,
(f) Certification stating that the ....................................
MIA Report required in Sec.
250.732(d) has been submitted
within the past 12 months for a
subsea BOP, a BOP being used in
an HPHT environment as defined in
Sec. 250.807, or a surface BOP
on a floating facility.
------------------------------------------------------------------------

Sec. 250.732 What are the BSEE-approved verification organization (BAVO)
requirements for BOP systems and system components?

(a) BSEE will maintain a list of BSEE-approved verification
organizations (BAVOs) on its public website that you must use to satisfy
any provision in this subpart that requires a BAVO certification,
verification, report, or review. You must comply with all requirements
in this subpart for BAVO certification, verification, or reporting no
later than 1 year from the date BSEE publishes a list of BAVOs.
(1) Until such time as you use a BAVO to perform the actions that
this subpart requires to be performed by a BAVO, but not after 1 year
from the date BSEE publishes a list of BAVOs, you must use an
independent third-party meeting the criteria specified in paragraph
(a)(2) of this section to prepare certifications, verifications, and
reports as required by Sec. Sec. 250.731(c) and (d), 250.732 (b) and
(c), 250.734(b)(1), 250.738(b)(4), and 250.739(b).
(2) The independent third-party must be a technical classification
society, or a licensed professional engineering firm, or a registered
professional engineer capable of providing the certifications,
verifications, and reports required under paragraph (a)(1) of this
section.
(3) For an organization to become a BAVO, it must submit the
following information to the Chief, Office of Offshore Regulatory
Programs; Bureau of Safety and Environmental Enforcement; 45600 Woodland
Road, Sterling, Virginia, 20166, for BSEE review and approval:
(i) Previous experience in verification or in the design,
fabrication, installation, repair, or major modification of BOPs and
related systems and equipment;
(ii) Technical capabilities;
(iii) Size and type of organization;
(iv) In-house availability of, or access to, appropriate technology.
This should include computer programs, hardware, and testing materials
and equipment;

[[Page 139]]

(v) Ability to perform the verification functions for projects
considering current commitments;
(vi) Previous experience with BSEE requirements and procedures; and
(vii) Any additional information that may be relevant to BSEE's
review.
(b) Prior to beginning any operation requiring the use of any BOP,
you must submit verification by a BAVO and supporting documentation as
required by this paragraph to the appropriate District Manager and
Regional Supervisor.

------------------------------------------------------------------------
You must submit verification and
documentation related to: That:
------------------------------------------------------------------------
(1) Shear testing,................ (i) Demonstrates that the BOP will
shear the drill pipe and any
electric-, wire-, and slick-line to
be used in the well, no later than
April 30, 2018;
(ii) Demonstrates the use of test
protocols and analysis that
represent recognized engineering
practices for ensuring the
repeatability and reproducibility
of the tests, and that the testing
was performed by a facility that
meets generally accepted quality
assurance standards;
(iii) Provides a reasonable
representation of field
applications, taking into
consideration the physical and
mechanical properties of the drill
pipe;
(iv) Ensures testing was performed
on the outermost edges of the
shearing blades of the shear ram
positioning mechanism as required
in Sec. 250.734(a)(16);
(v) Demonstrates the shearing
capacity of the BOP equipment to
the physical and mechanical
properties of the drill pipe; and
(vi) Includes relevant testing
results.
(2) Pressure integrity testing, (i) Shows that testing is conducted
and. immediately after the shearing
tests;
(ii) Demonstrates that the equipment
will seal at the rated working
pressures (RWP) of the BOP for 30
minutes; and
(iii) Includes all relevant test
results.
(3) Calculations.................. Include shearing and sealing
pressures for all pipe to be used
in the well including corrections
for MASP.
------------------------------------------------------------------------

(c) For wells in an HPHT environment, as defined by Sec.
250.807(b), you must submit verification by a BAVO that the verification
organization conducted a comprehensive review of the BOP system and
related equipment you propose to use. You must provide the BAVO access
to any facility associated with the BOP system or related equipment
during the review process. You must submit the verifications required by
this paragraph (c) to the appropriate District Manager and Regional
Supervisor before you begin any operations in an HPHT environment with
the proposed equipment.

------------------------------------------------------------------------
You must submit: Including:
------------------------------------------------------------------------
(1) Verification that the
verification organization conducted
a detailed review of the design
package to ensure that all critical
components and systems meet
recognized engineering practices,
(2) Verification that the designs of (i) Identification of all
individual components and the reasonable potential modes of
overall system have been proven in a failure; and
testing process that demonstrates (ii) Evaluation of the design
the performance and reliability of verification tests. The design
the equipment in a manner that is verification tests must assess
repeatable and reproducible, the equipment for the identified
potential modes of failure.
(3) Verification that the BOP
equipment will perform as designed
in the temperature, pressure, and
environment that will be
encountered, and
(4) Verification that the For the quality control and
fabrication, manufacture, and assurance mechanisms, complete
assembly of individual components material and quality controls
and the overall system uses over all contractors,
recognized engineering practices and subcontractors, distributors,
quality control and assurance and suppliers at every stage in
mechanisms. the fabrication, manufacture,
and assembly process.
------------------------------------------------------------------------

(d) Once every 12 months, you must submit a Mechanical Integrity
Assessment Report for a subsea BOP, a BOP being used in an HPHT
environment as defined in Sec. 250.807, or a surface BOP on a floating
facility. This report must be completed by a BAVO. You must submit this
report to the Chief, Office of Offshore Regulatory Programs; Bureau

[[Page 140]]

of Safety and Environmental Enforcement; 45600 Woodland Road, Sterling,
VA 20166. This report must include:
(1) A determination that the BOP stack and system meets or exceeds
all BSEE regulatory requirements, industry standards incorporated into
this subpart, and recognized engineering practices.
(2) Verification that complete documentation of the equipment's
service life exists that demonstrates that the BOP stack has not been
compromised or damaged during previous service.
(3) A description of all inspection, repair and maintenance records
reviewed, and verification that all repairs, replacement parts, and
maintenance meet regulatory requirements, recognized engineering
practices, and OEM specifications.
(4) A description of records reviewed related to any modifications
to the equipment and verification that any such changes do not adversely
affect the equipment's capability to perform as designed or invalidate
test results.
(5) A description of the Safety and Environmental Management Systems
(SEMS) plans reviewed related to assurance of quality and mechanical
integrity of critical equipment and verification that the plans are
comprehensive and fully implemented.
(6) Verification that the qualification and training of inspection,
repair, and maintenance personnel for the BOP systems meet recognized
engineering practices and any applicable OEM requirements.
(7) A description of all records reviewed covering OEM safety
alerts, all failure reports, and verification that any design or
maintenance issues have been completely identified and corrected.
(8) A comprehensive assessment of the overall system and
verification that all components (including mechanical, hydraulic,
electrical, and software) are compatible.
(9) Verification that documentation exists concerning the
traceability of the fabrication, repair, and maintenance of all critical
components.
(10) Verification of use of a formal maintenance tracking system to
ensure that corrective maintenance and scheduled maintenance is
implemented in a timely manner.
(11) Identification of gaps or deficiencies related to inspection
and maintenance procedures and documentation, documentation of any
deferred maintenance, and verification of the completion of corrective
action plans.
(12) Verification that any inspection, maintenance, or repair work
meets the manufacturer's design and material specifications.
(13) Verification of written procedures for operating the BOP stack
and Lower Marine Riser Package (LMRP) (including proper techniques to
prevent accidental disconnection of these components) and minimum
knowledge requirements for personnel authorized to operate and maintain
BOP components.
(14) Recommendations, if any, for how to improve the fabrication,
installation, operation, maintenance, inspection, and repair of the
equipment.
(e) You must make all documentation that supports the requirements
of this section available to BSEE upon request.

Sec. 250.733 What are the requirements for a surface BOP stack?

(a) When you drill or conduct operations with a surface BOP stack,
you must install the BOP system before drilling or conducting operations
to deepen the well below the surface casing and after the well is
deepened below the surface casing point. The surface BOP stack must
include at least four remote-controlled, hydraulically operated BOPs,
consisting of one annular BOP, one BOP equipped with blind shear rams,
and two BOPs equipped with pipe rams.
(1) The blind shear rams must be capable of shearing at any point
along the tubular body of any drill pipe (excluding tool joints, bottom-
hole tools, and bottom hole assemblies that include heavy-weight pipe or
collars), workstring, tubing provided that the capability to shear
tubing with exterior control lines is not required prior to April 30,
2018, and any electric-, wire-, and slick-line that is in the hole and
sealing the wellbore after shearing. If your blind shear rams are unable
to

[[Page 141]]

cut any electric-, wire-, or slick-line under MASP as defined for the
operation and seal the wellbore, you must use an alternative cutting
device capable of shearing the lines before closing the BOP. This device
must be available on the rig floor during operations that require their
use.
(2) The two BOPs equipped with pipe rams must be capable of closing
and sealing on the tubular body of any drill pipe, workstring, and
tubing under MASP, as defined for the operation, except for tubing with
exterior control lines and flat packs, a bottom hole assembly that
includes heavy-weight pipe or collars, and bottom-hole tools.
(b) If you plan to use a surface BOP on a floating production
facility you must:
(1) For BOPs installed after April 29, 2019, follow the BOP
requirements in Sec. 250.734(a)(1).
(2) For risers installed after July 28, 2016, use a dual bore riser
configuration before drilling or operating in any hole section or
interval where hydrocarbons are, or may be, exposed to the well. The
dual bore riser must meet the design requirements of API RP 2RD (as
incorporated by reference in Sec. 250.198), including appropriate
design for the maximum anticipated operating and environmental
conditions.
(i) For a dual bore riser configuration, the annulus between the
risers must be monitored for pressure during operations. You must
describe in your APD or APM your annulus monitoring plan and how you
will secure the well in the event a leak is detected.
(ii) The inner riser for a dual riser configuration is subject to
the requirements at Sec. 250.721 for testing the casing or liner.
(c) You must install separate side outlets on the BOP stack for the
kill and choke lines. If your stack does not have side outlets, you must
install a drilling spool with side outlets. The outlet valves must hold
pressure from both directions.
(d) You must install a choke and a kill line on the BOP stack. You
must equip each line with two full-bore, full-opening valves, one of
which must be remote-controlled. On the kill line, you may install a
check valve and a manual valve instead of the remote-controlled valve.
To use this configuration, both manual valves must be readily accessible
and you must install the check valve between the manual valves and the
pump.

Sec. 250.734 What are the requirements for a subsea BOP system?

(a) When you drill or conduct operations with a subsea BOP system,
you must install the BOP system before drilling to deepen the well below
the surface casing or before conducting operations if the well is
already deepened beyond the surface casing point. The District Manager
may require you to install a subsea BOP system before drilling or
conducting operations below the conductor casing if proposed casing
setting depths or local geology indicate the need. The following table
outlines your requirements.

------------------------------------------------------------------------
When operating with a subsea BOP system,
you must: Additional requirements:
------------------------------------------------------------------------
(1) Have at least five remote-controlled, You must have at least one
hydraulically operated BOPs; annular BOP, two BOPs
equipped with pipe rams,
and two BOPs equipped with
shear rams. For the dual
ram requirement, you must
comply with this
requirement no later than
April 29, 2021.
(i) Both BOPs equipped with
pipe rams must be capable
of closing and sealing on
the tubular body of any
drill pipe, workstring, and
tubing under MASP, as
defined for the operation,
except tubing with exterior
control lines and flat
packs, a bottom hole
assembly that includes
heavy-weight pipe or
collars, and bottom-hole
tools.

[[Page 142]]

(ii) Both shear rams must be
capable of shearing at any
point along the tubular
body of any drill pipe
(excluding tool joints,
bottom-hole tools, and
bottom hole assemblies such
as heavy-weight pipe or
collars), workstring,
tubing provided that the
capability to shear tubing
with exterior control lines
is not required prior to
April 30, 2018, appropriate
area for the liner or
casing landing string,
shear sub on subsea test
tree, and any electric-,
wire-, slick-line in the
hole no later than April
30, 2018; under MASP. At
least one shear ram must be
capable of sealing the
wellbore after shearing
under MASP conditions as
defined for the operation.
Any non-sealing shear
ram(s) must be installed
below a sealing shear
ram(s).
(2) Have an operable redundant pod control
system to ensure proper and independent
operation of the BOP system;
(3) Have the accumulator capacity located The accumulator capacity
subsea, to provide fast closure of the must:
BOP components and to operate all (i) Operate each required
critical functions in case of a loss of shear ram, ram locks, one
the power fluid connection to the pipe ram, and disconnect
surface; the LMRP.
(ii) Have the capability of
delivering fluid to each
ROV function i.e., flying
leads.
(iii) No later than April
29, 2021, have bottles for
the autoshear, and deadman
that are dedicated to, but
may be shared between,
those functions.
(iv) Perform under MASP
conditions as defined for
the operation.
(4) Have a subsea BOP stack equipped with The ROV must be capable of
remotely operated vehicle (ROV) opening and closing each
intervention capability; shear ram, ram locks, one
pipe ram, and LMRP
disconnect under MASP
conditions as defined for
the operation. The ROV
panels on the BOP and LMRP
must be compliant with API
RP 17H (as incorporated by
reference in Sec.
250.198).
(5) Maintain an ROV and have a trained ROV The crew must be trained in
crew on each rig unit on a continuous the operation of the ROV.
basis once BOP deployment has been The training must include
initiated from the rig until recovered to simulator training on
the surface. The ROV crew must examine stabbing into an ROV
all ROV-related well-control equipment intervention panel on a
(both surface and subsea) to ensure that subsea BOP stack. The ROV
it is properly maintained and capable of crew must be in
carrying out appropriate tasks during communication with
emergency operations; designated rig personnel
who are knowledgeable about
the BOP's capabilities.
(6) Provide autoshear, deadman, and EDS (i) Autoshear system means a
systems for dynamically positioned rigs; safety system that is
provide autoshear and deadman systems for designed to automatically
moored rigs; shut-in the wellbore in the
event of a disconnect of
the LMRP. This is
considered a rapid
discharge system.
(ii) Deadman system means a
safety system that is
designed to automatically
shut-in the wellbore in the
event of a simultaneous
absence of hydraulic supply
and signal transmission
capacity in both subsea
control pods. This is
considered a rapid
discharge system.
(iii) Emergency Disconnect
Sequence (EDS) system means
a safety system that is
designed to be manually
activated to shut-in the
wellbore and disconnect the
LMRP in the event of an
emergency situation. This
is considered a rapid
discharge system.
(iv) Each emergency function
must close at a minimum,
two shear rams in sequence
and be capable of
performing its expected
shearing and sealing action
under MASP conditions as
defined for the operation.
(v) Your sequencing must
allow a sufficient delay
for closing the upper shear
ram after beginning closure
of the lower shear ram to
provide for maximum sealing
efficiency.
(vi) The control system for
the emergency functions
must be a fail-safe design
once activated.
(7) Demonstrate that any acoustic control If you choose to use an
system will function in the proposed acoustic control system in
environment and conditions; addition to the autoshear,
deadman, and EDS
requirements, you must
demonstrate to the District
Manager, as part of the
information submitted under
Sec. 250.731, that the
acoustic control system
will function in the
proposed environment and
conditions. The District
Manager may require
additional information as
appropriate to clarify or
evaluate the acoustic
control system information
provided in your
demonstration.
(8) Have operational or physical You must incorporate enable
barrier(s) on BOP control panels to buttons, or a similar
prevent accidental disconnect functions; feature, on control panels
to ensure two-handed
operation for all critical
functions.
(9) Clearly label all control panels for Label other BOP control
the subsea BOP system; panels, such as hydraulic
control panel.

[[Page 143]]

(10) Develop and use a management system The management system must
for operating the BOP system, including include written procedures
the prevention of accidental or unplanned for operating the BOP stack
disconnects of the system; and LMRP (including proper
techniques to prevent
accidental disconnection of
these components) and
minimum knowledge
requirements for personnel
authorized to operate and
maintain BOP components.
(11) Establish minimum requirements for Personnel must have:
personnel authorized to operate critical (i) Training in deepwater
BOP equipment; well-control theory and
practice according to the
requirements of Subparts O
and S; and
(ii) A comprehensive
knowledge of BOP hardware
and control systems.
(12) Before removing the marine riser, You must maintain sufficient
displace the fluid in the riser with hydrostatic pressure or
seawater; take other suitable
precautions to compensate
for the reduction in
pressure and to maintain a
safe and controlled well
condition. You must follow
the requirements of Sec.
250.720(b).
(13) Install the BOP stack in a well Your well cellar must be
cellar when in an ice-scour area; deep enough to ensure that
the top of the stack is
below the deepest probable
ice-scour depth.
(14) Install at least two side outlets for (i) If your stack does not
a choke line and two side outlets for a have side outlets, you must
kill line; install a drilling spool
with side outlets.
(ii) Each side outlet must
have two full-bore, full-
opening valves.
(iii) The valves must hold
pressure from both
directions and must be
remote-controlled.
iv) You must install a side
outlet below the lowest
sealing shear ram. You may
have a pipe ram or rams
between the shearing ram
and side outlet.
(15) Install a gas bleed line with two (i) The valves must hold
valves for the annular preventer no later pressure from both
than April 30, 2018; directions;
(ii) If you have dual
annulars, you must install
the gas bleed line below
the upper annular.
(16) Use a BOP system that has the (i) A mechanism coupled with
following mechanisms and capabilities; each shear ram to position
the entire pipe, completely
within the area of the
shearing blade and ensure
shearing will occur any
time the shear rams are
activated. This mechanism
cannot be another ram BOP
or annular preventer, but
you may use those during a
planned shear. You must
install this mechanism no
later than May 1, 2023;
(ii) The ability to mitigate
compression of the pipe
stub between the shearing
rams when both shear rams
are closed;
(iii) If your control pods
contain a subsea electronic
module with batteries, a
mechanism for personnel on
the rig to monitor the
state of charge of the
subsea electronic module
batteries in the BOP
control pods.
------------------------------------------------------------------------

(b) If operations are suspended to make repairs to any part of the
subsea BOP system, you must stop operations at a safe downhole location.
Before resuming operations you must:
(1) Submit a revised permit with a verification report from a BAVO
documenting the repairs and that the BOP is fit for service;
(2) Upon relatch of the BOP, perform an initial subsea BOP test in
accordance with Sec. 250.737(d)(4), including deadman. If repairs take
longer than 30 days, once the BOP is on deck, you must test in
accordance with the requirements of Sec. 250.737; and
(3) Receive approval from the District Manager.
(c) If you plan to drill a new well with a subsea BOP, you do not
need to submit with your APD the verifications required by this subpart
for the open water drilling operation. Before drilling out the surface
casing, you must submit for approval a revised APD, including the
verifications required in this subpart.

Sec. 250.735 What associated systems and related equipment must all
BOP systems include?

All BOP systems must include the following associated systems and
related equipment:
(a) An accumulator system (as specified in API Standard 53, and
incorporated by reference in Sec. 250.198) that provides the volume of
fluid capacity (as specified in API Standard 53, Annex C) necessary to
close and hold closed all BOP components against MASP. The system must
operate under MASP conditions as defined for the operation. You must be
able to operate the BOP functions as defined in API Standard 53, without
assistance from a charging

[[Page 144]]

system, and still have a minimum pressure of 200 psi remaining on the
bottles above the pre-charge pressure. If you supply the accumulator
regulators by rig air and do not have a secondary source of pneumatic
supply, you must equip the regulators with manual overrides or other
devices to ensure capability of hydraulic operations if rig air is lost;
(b) An automatic backup to the primary accumulator-charging system.
The power source must be independent from the power source for the
primary accumulator-charging system. The independent power source must
possess sufficient capability to close and hold closed all BOP
components under MASP conditions as defined for the operation;
(c) At least two full BOP control stations. One station must be on
the rig floor. You must locate the other station in a readily accessible
location away from the rig floor;
(d) The choke line(s) installed above the bottom well-control ram;
(e) The kill line must be installed beneath at least one well-
control ram, and may be installed below the bottom ram;
(f) A fill-up line above the uppermost BOP;
(g) Locking devices for all BOP sealing rams (i.e., blind shear
rams, pipe rams and variable bore rams), as follows:
(1) For subsea BOPs, hydraulic locking devices must be installed on
all sealing rams;
(2) For surface BOPs:
(i) Remotely-operated locking devices must be installed on blind
shear rams no later than April 29, 2019;
(ii) Manual or remotely-operated locking devices must be installed
on pipe rams and variable bore rams; and
(h) A wellhead assembly with a RWP that exceeds the maximum
anticipated wellhead pressure.

Sec. 250.736 What are the requirements for choke manifolds, kelly-type
valves inside BOPs, and drill string safety valves?

(a) Your BOP system must include a choke manifold that is suitable
for the anticipated surface pressures, anticipated methods of well
control, the surrounding environment, and the corrosiveness, volume, and
abrasiveness of drilling fluids and well fluids that you may encounter.
(b) Choke manifold components must have a RWP at least as great as
the RWP of the ram BOPs. If your choke manifold has buffer tanks
downstream of choke assemblies, you must install isolation valves on any
bleed lines.
(c) Valves, pipes, flexible steel hoses, and other fittings upstream
of the choke manifold must have a RWP at least as great as the RWP of
the ram BOPs.
(d) You must use the following BOP equipment with a RWP and
temperature of at least as great as the working pressure and temperature
of the ram BOP during all operations:
(1) The applicable kelly-type valves as described in API Standard 53
(incorporated by reference in Sec. 250.198);
(2) On a top-drive system equipped with a remote-controlled valve, a
strippable kelly-type valve must be installed below the remote-
controlled valve;
(3) An inside BOP in the open position located on the rig floor. You
must be able to install an inside BOP for each size connection in the
pipe;
(4) A drill string safety valve in the open position located on the
rig floor. You must have a drill-string safety valve available for each
size connection in the pipe;
(5) When running casing, a safety valve in the open position
available on the rig floor to fit the casing string being run in the
hole;
(6) All required manual and remote- controlled kelly-type valves,
drill-string safety valves, and comparable-type valves (i.e., kelly-type
valve in a top-drive system) that are essentially full opening; and
(7) A wrench to fit each manual valve. Each wrench must be readily
accessible to the drilling crew.

Sec. 250.737 What are the BOP system testing requirements?

Your BOP system (this includes the choke manifold, kelly-type
valves, inside BOP, and drill string safety valve) must meet the
following testing requirements:
(a) Pressure test frequency. You must pressure test your BOP system:

[[Page 145]]

(1) When installed;
(2) Before 14 days have elapsed since your last BOP pressure test,
or 30 days since your last blind shear ram BOP pressure test. You must
begin to test your BOP system before midnight on the 14th day (or 30th
day for your blind shear rams) following the conclusion of the previous
test;
(3) Before drilling out each string of casing or a liner. You may
omit this pressure test requirement if you did not remove the BOP stack
to run the casing string or liner, the required BOP test pressures for
the next section of the hole are not greater than the test pressures for
the previous BOP test, and the time elapsed between tests has not
exceeded 14 days (or 30 days for blind shear rams). You must indicate in
your APD which casing strings and liners meet these criteria;
(4) The District Manager may require more frequent testing if
conditions or your BOP performance warrant.
(b) Pressure test procedures. When you pressure test the BOP system,
you must conduct a low-pressure test and a high-pressure test for each
BOP component. You must begin each test by conducting the low-pressure
test then transition to the high-pressure test. Each individual pressure
test must hold pressure long enough to demonstrate the tested
component(s) holds the required pressure. The table in this paragraph
(b) outlines your pressure test requirements.

------------------------------------------------------------------------
According to the following
You must conduct a . . . procedures . . .
------------------------------------------------------------------------
(1) Low-pressure test............. All low-pressure tests must be
between 250 and 350 psi. Any
initial pressure above 350 psi must
be bled back to a pressure between
250 and 350 psi before starting the
test. If the initial pressure
exceeds 500 psi, you must bleed
back to zero and reinitiate the
test.
(2) High-pressure test for blind The high-pressure test must equal
shear ram-type BOPs, ram-type the RWP of the equipment or be 500
BOPs, the choke manifold, outside psi greater than your calculated
of all choke and kill side outlet MASP, as defined for the operation
valves (and annular gas bleed for the applicable section of hole.
valves for subsea BOP), inside of Before you may test BOP equipment
all choke and kill side outlet to the MASP plus 500 psi, the
valves below uppermost ram, and District Manager must have approved
other BOP components. those test pressures in your APD.
(3) High-pressure test for annular- The high pressure test must equal 70
type BOPs, inside of choke or percent of the RWP of the equipment
kill valves (and annular gas or be 500 psi greater than your
bleed valves for subsea BOP) calculated MASP, as defined for the
above the uppermost ram BOP. operation for the applicable
section of hole. Before you may
test BOP equipment to the MASP plus
500 psi, the District Manager must
have approved those test pressures
in your APD.
------------------------------------------------------------------------

(c) Duration of pressure test. Each test must hold the required
pressure for 5 minutes, which must be recorded on a chart not exceeding
4 hours. However, for surface BOP systems and surface equipment of a
subsea BOP system, a 3-minute test duration is acceptable if recorded on
a chart not exceeding 4 hours, or on a digital recorder. The recorded
test pressures must be within the middle half of the chart range, i.e.,
cannot be within the lower or upper one-fourth of the chart range. If
the equipment does not hold the required pressure during a test, you
must correct the problem and retest the affected component(s).
(d) Additional test requirements. You must meet the following
additional BOP testing requirements:

------------------------------------------------------------------------
You must . . . Additional requirements . . .
------------------------------------------------------------------------
(1) Follow the testing If there is a conflict between API
requirements of API Standard 53 Standard 53, testing requirements
(as incorporated in Sec. and this section, you must follow
250.198). the requirements of this section.
(2) Use water to test a surface (i) You must submit test procedures
BOP system on the initial test. with your APD or APM for District
You may use drilling/completion/ Manager approval.
workover fluids to conduct (ii) Contact the District Manager at
subsequent tests of a surface BOP least 72 hours prior to beginning
system. the initial test to allow BSEE
representative(s) to witness
testing. If BSEE representative(s)
are unable to witness testing, you
must provide the initial test
results to the appropriate District
Manager within 72 hours after
completion of the tests.
(3) Stump test a subsea BOP system (i) You must use water to conduct
before installation. this test. You may use drilling/
completion/workover fluids to
conduct subsequent tests of a
subsea BOP system.

[[Page 146]]

(ii) You must submit test procedures
with your APD or APM for District
Manager approval
(iii) Contact the District Manager
at least 72 hours prior to
beginning the stump test to allow
BSEE representative(s) to witness
testing. If BSEE representative(s)
are unable to witness testing, you
must provide the test results to
the appropriate District Manager
within 72 hours after completion of
the tests.
(iv) You must test and verify
closure of all ROV intervention
functions on your subsea BOP stack
during the stump test.
(v) You must follow paragraphs (b)
and (c) of this section.
(4) Perform an initial subsea BOP (i) You must perform the initial
test. subsea BOP test on the seafloor
within 30 days of the stump test.
(ii) You must submit test procedures
with your APD or APM for District
Manager approval.
(iii) You must pressure test well-
control rams according to
paragraphs (b) and (c) of this
section.
(iv) You must notify the District
Manager at least 72 hours prior to
beginning the initial subsea test
for the BOP system to allow BSEE
representative(s) to witness
testing.
(v) You must test and verify closure
of at least one set of rams during
the initial subsea test through a
ROV hot stab.
(vi) You must pressure test the
selected rams according to
paragraphs (b) and (c) of this
section.
(5) Alternate testing pods between (i) For two complete BOP control
control stations. stations:
(A) Designate a primary and
secondary station, and both
stations must be function-tested
weekly;
(B) The control station used for the
pressure test must be alternated
between pressure tests; and
(C) For a subsea BOP, the pods must
be rotated between control stations
during weekly function testing and
14 day pressure testing.
(ii) Remote panels where all BOP
functions are not included (e.g.,
life boat panels) must be function-
tested upon the initial BOP tests
and monthly thereafter.
(6) Pressure test variable bore-
pipe ram BOPs against pipe sizes
according to API Standard 53,
excluding the bottom hole
assembly that includes heavy-
weight pipe or collars and bottom-
hole tools.
(7) Pressure test annular type
BOPs against pipe sizes according
to API Standard 53.
(8) Pressure test affected BOP
components following the
disconnection or repair of any
well-pressure containment seal in
the wellhead or BOP stack
assembly.
(9) Function test annular and pipe/
variable bore ram BOPs every 7
days between pressure tests.
(10) Function test shear ram(s)
BOPs every 14 days.
(11) Actuate safety valves
assembled with proper casing
connections before running casing.

[[Page 147]]

(12) Function test autoshear/ (i) You must submit test procedures
deadman, and EDS systems with your APD or APM for District
separately on your subsea BOP Manager approval. The procedures
stack during the stump test. The for these function tests must
District Manager may require include the schematics of the
additional testing of the actual controls and circuitry of
emergency systems. You must also the system that will be used during
test the deadman system and an actual autoshear or deadman
verify closure of the shearing event.
rams during the initial test on (ii) The procedures must also
the seafloor. include the actions and sequence of
events that take place on the
approved schematics of the BOP
control system and describe
specifically how the ROV will be
utilized during this operation.
(iii) When you conduct the initial
deadman system test on the
seafloor, you must ensure the well
is secure and, if hydrocarbons have
been present, appropriate barriers
are in place to isolate
hydrocarbons from the wellhead. You
must also have an ROV on bottom
during the test.
(iv) The testing of the deadman
system on the seafloor must
indicate the discharge pressure of
the subsea accumulator system
throughout the test.
(v) For the function test of the
deadman system during the initial
test on the seafloor, you must have
the ability to quickly disconnect
the LMRP should the rig experience
a loss of station-keeping event.
You must include your quick-
disconnect procedures with your
deadman test procedures.
(vi) You must pressure test the
blind shear ram(s) according to
paragraphs (b) and (c) of this
section.
(vii) If a casing shear ram is
installed, you must describe how
you will verify closure of the ram.
(viii) You must document all your
test results and make them
available to BSEE upon request.
------------------------------------------------------------------------

(e) Prior to conducting any shear ram tests in which you will shear
pipe, you must notify the District Manager at least 72 hours in advance,
to ensure that a BSEE representative will have access to the location to
witness any testing.

Sec. 250.738 What must I do in certain situations involving BOP
equipment or systems?

The table in this section describes actions that you must take when
certain situations occur with BOP systems.

------------------------------------------------------------------------
If you encounter the following
situation: Then you must . . .
------------------------------------------------------------------------
(a) BOP equipment does not hold the Correct the problem and retest
required pressure during a test; the affected equipment. You must
report any problems or
irregularities, including any
leaks, on the daily report as
required in Sec. 250.746.
(b) Need to repair, replace, or (1) First place the well in a
reconfigure a surface or subsea BOP safe, controlled condition as
system; approved by the District Manager
(e.g., before drilling out a
casing shoe or after setting a
cement plug, bridge plug, or a
packer).
(2) Any repair or replacement
parts must be manufactured under
a quality assurance program and
must meet or exceed the
performance of the original part
produced by the OEM.
(3) You must receive approval
from the District Manager prior
to resuming operations with the
new, repaired, or reconfigured
BOP.
(4) You must submit a report from
a BAVO to the District Manager
certifying that the BOP is fit
for service.
(c) Need to postpone a BOP test due Record the reason for postponing
to well-control problems such as the test in the daily report and
lost circulation, formation fluid conduct the required BOP test
influx, or stuck pipe; after the first trip out of the
hole.
(d) BOP control station or pod that Suspend operations until that
does not function properly; station or pod is operable. You
must report any problems or
irregularities, including any
leaks, to the District Manager.
(e) Plan to operate with a tapered Install two or more sets of
string; conventional or variable-bore
pipe rams in the BOP stack to
provide for the following: two
sets of rams must be capable of
sealing around the larger-size
drill string and one set of pipe
rams must be capable of sealing
around the smaller size pipe,
excluding the bottom hole
assembly that includes heavy
weight pipe or collars and
bottom-hole tools.
(f) Plan to install casing rams or Test the affected connections
casing shear rams in a surface BOP before running casing to the RWP
stack; or MASP plus 500 psi. If this
installation was not included in
your approved permit, and
changes the BOP configuration
approved in the APD or APM, you
must notify and receive approval
from the District Manager.
(g) Plan to use an annular BOP with a Demonstrate that your well-
RWP less than the anticipated control procedures or the
surface pressure; anticipated well conditions will
not place demands above its RWP
and obtain approval from the
District Manager.

[[Page 148]]

(h) Plan to use a subsea BOP system Install the BOP stack in a well
in an ice-scour area; cellar. The well cellar must be
deep enough to ensure that the
top of the stack is below the
deepest probable ice-scour
depth.
(i) You activate any shear ram and Retrieve, physically inspect, and
pipe or casing is sheared; conduct a full pressure test of
the BOP stack after the
situation is fully controlled.
You must submit to the District
Manager a report from a BSEE-
approved verification
organization certifying that the
BOP is fit to return to service.
(j) Need to remove the BOP stack; Have a minimum of two barriers in
place prior to BOP removal. You
must obtain approval from the
District Manager of the two
barriers prior to removal and
the District Manager may require
additional barriers and test(s).
(k) In the event of a deadman or Place the blind shear ram opening
autoshear activation, if there is a function in the block position
possibility of the blind shear ram prior to re-establishing power
opening immediately upon re- to the stack. Contact the
establishing power to the BOP stack; District Manager and receive
approval of procedures for re-
establishing power and functions
prior to latching up the BOP
stack or re-establishing power
to the stack.
(l) If a test ram is to be used; The wellhead/BOP connection must
be tested to the MASP plus 500
psi for the hole section to
which it is exposed. This can be
done by:
(1) Testing wellhead/BOP
connection to the MASP plus 500
psi for the well upon
installation;
(2) Pressure testing each casing
to the MASP plus 500 psi for the
next hole section; or
(3) Some combination of
paragraphs (l)(1) and (2) of
this section.
(m) Plan to utilize any other well- Contact the District Manager and
control equipment (e.g., but not request approval in your APD or
limited to, subsea isolation device, APM. Your request must include a
subsea accumulator module, or gas report from a BAVO on the
handler) that is in addition to the equipment's design and
equipment required in this subpart; suitability for its intended use
as well as any other information
required by the District
Manager. The District Manager
may impose any conditions
regarding the equipment's
capabilities, operation, and
testing.
(n) You have pipe/variable bore rams Indicate in your APD or APM which
that have no current utility or well- pipe/variable bore rams meet
control purposes; these criteria and clearly label
them on all BOP control panels.
You do not need to function test
or pressure test pipe/variable
bore rams having no current
utility, and that will not be
used for well-control purposes,
until such time as they are
intended to be used during
operations.
(o) You install redundant components Comply with all testing,
for well control in your BOP system maintenance, and inspection
that are in addition to the required requirements in this subpart
components of this subpart (e.g., that are applicable to those
pipe/variable bore rams, shear rams, well-control components. If any
annular preventers, gas bleed lines, redundant component fails a
and choke/kill side outlets or test, you must submit a report
lines); from a BAVO that describes the
failure and confirms that there
is no impact on the BOP that
will make it unfit for well-
control purposes. You must
submit this report to the
District Manager and receive
approval before resuming
operations. The District Manager
may require you to provide
additional information as needed
to clarify or evaluate your
report.
(p) Need to position the bottom hole Ensure that the well is stable
assembly, including heavy-weight prior to positioning the bottom
pipe or collars, and bottom-hole hole assembly across the BOP.
tools across the BOP for tripping or You must have, as part of your
any other operations. well-control plan required by
Sec. 250.710, procedures that
enable the removal of the bottom
hole assembly from across the
BOP in the event of a well-
control or emergency situation
(for dynamically positioned
rigs, your plan must also
include steps for when the EDS
must be activated) before MASP
conditions are reached as
defined for the operation.
------------------------------------------------------------------------

Sec. 250.739 What are the BOP maintenance and inspection requirements?

(a) You must maintain and inspect your BOP system to ensure that the
equipment functions as designed. The BOP maintenance and inspections
must meet or exceed any OEM recommendations, recognized engineering
practices, and industry standards incorporated by reference into the
regulations of this subpart, including API Standard 53 (incorporated by
reference in Sec. 250.198). You must document how you met or exceeded
the provisions of API Standard 53, maintain complete records to ensure
the traceability of BOP stack equipment beginning at fabrication, and
record the results of your BOP inspections and maintenance actions. You
must make all records available to BSEE upon request.
(b) A complete breakdown and detailed physical inspection of the BOP
and every associated system and component must be performed every 5
years. This complete breakdown and inspection may be performed in phased
intervals. You must track and document all system and component
inspection dates. These records must be available on the rig. A BAVO is
required to be present during each inspection and must compile a
detailed report documenting the inspection, including descriptions of
any problems

[[Page 149]]

and how they were corrected. You must make these reports available to
BSEE upon request. This complete breakdown and inspection must be
performed every 5 years from the following applicable dates, whichever
is later:
(1) The date the equipment owner accepts delivery of a new build
drilling rig with a new BOP system;
(2) The date the new, repaired, or remanufactured equipment is
initially installed into the system; or
(3) The date of the last 5 year inspection for the component.
(c) You must visually inspect your surface BOP system on a daily
basis. You must visually inspect your subsea BOP system, marine riser,
and wellhead at least once every 3 days if weather and sea conditions
permit. You may use cameras to inspect subsea equipment.
(d) You must ensure that all personnel maintaining, inspecting, or
repairing BOPs, or critical components of the BOP system, are trained in
accordance with applicable training requirements in subpart S of this
part, any applicable OEM criteria, recognized engineering practices, and
industry standards incorporated by reference in this subpart.
(e) You must make all records available to BSEE upon request. You
must ensure that the rig unit owner maintains the BOP maintenance,
inspection, and repair records on the rig unit for 2 years from the date
the records are created or for a longer period if directed by BSEE. You
must ensure that all equipment schematics, maintenance, inspection, and
repair records are located at an onshore location for the service life
of the equipment.

Records and Reporting

Sec. 250.740 What records must I keep?

You must keep a daily report consisting of complete, legible, and
accurate records for each well. You must keep records onsite while well
operations continue. After completion of operations, you must keep all
operation and other well records for the time periods shown in Sec.
250.741 at a location of your choice, except as required in Sec.
250.746. The records must contain complete information on all of the
following:
(a) Well operations, all testing conducted, and any real-time
monitoring data as required by Sec. 250.724;
(b) Descriptions of formations penetrated;
(c) Content and character of oil, gas, water, and other mineral
deposits in each formation;
(d) Kind, weight, size, grade, and setting depth of casing;
(e) All well logs and surveys run in the wellbore;
(f) Any significant malfunction or problem; and
(g) All other information required by the District Manager as
appropriate to ensure compliance with the requirements of this section
and to enable BSEE to determine that the well operations are consistent
with conservation of natural resources and protection of safety and the
environment on the OCS.

Sec. 250.741 How long must I keep records?

You must keep records for the time periods shown in the following
table.

------------------------------------------------------------------------
You must keep records relating to . . . Until . . .
------------------------------------------------------------------------
(a) Drilling; 90 days after you complete
operations.
(b) Casing and liner pressure tests, 2 years after the completion
diverter tests, BOP tests, and real-time of operations.
monitoring data;
(c) Completion of a well or of any You permanently plug and
workover activity that materially alters abandon the well or until
the completion configuration or affects a you assign the lease and
hydrocarbon-bearing zone. forward the records to the
assignee.
------------------------------------------------------------------------

Sec. 250.742 What well records am I required to submit?

You must submit to BSEE copies of logs or charts of electrical,
radioactive, sonic, and other well logging operations; directional and
vertical well surveys; velocity profiles and surveys; and analysis of
cores. Each Region will provide specific instructions for submitting
well logs and surveys.

[[Page 150]]

Sec. 250.743 What are the well activity reporting requirements?

(a) For operations in the BSEE Gulf of Mexico (GOM) OCS Region, you
must submit Form BSEE-0133, Well Activity Report (WAR), to the District
Manager on a weekly basis. The reporting week is defined as beginning on
Sunday (12 a.m.) and ending on the following Saturday (11:59 p.m.). This
reporting week corresponds to a week (Sunday through Saturday) on a
standard calendar. Report any well operations that extend past the end
of this weekly reporting period on the next weekly report. The reporting
period for the weekly report is never longer than 7 days, but could be
less than 7 days for the first reporting period and the last reporting
period for a particular well operation. Submit each WAR and accompanying
Form BSEE-0133S, Open Hole Data Report, to the BSEE GOM OCS Region no
later than close of business on the Friday immediately after the closure
of the reporting week. The District Manager may require more frequent
submittal of the WAR on a case-by-case basis.
(b) For operations in the Pacific or Alaska OCS Regions, you must
submit Form BSEE-0133, WAR, to the District Manager on a daily basis.
(c) The WAR must include a description of the operations conducted,
any abnormal or significant events that affect the permitted operation
each day within the report from the time you begin operations to the
time you end operations, any verbal approval received, the well's as-
built drawings, casing, fluid weights, shoe tests, test pressures at
surface conditions, and any other information concerning well activities
required by the District Manager. For casing cementing operations,
indicate type of returns (i.e., full, partial, or none). If partial or
no returns are observed, you must indicate how you determined the top of
cement. For each report, indicate the operation status for the well at
the end of the reporting period. On the final WAR, indicate the status
of the well (completed, temporarily abandoned, permanently abandoned, or
drilling suspended) and the date you finished such operations.

Sec. 250.744 What are the end of operation reporting requirements?

(a) Within 30 days after completing operations, except routine
operations as defined in Sec. 250.601, you must submit Form BSEE-0125,
End of Operations Report (EOR), to the District Manager. The EOR must
include: a listing, with top and bottom depths, of all hydrocarbon zones
and other zones of porosity encountered with any cored intervals;
details on any drill-stem and formation tests conducted; documentation
of successful negative pressure testing on wells that use a subsea BOP
stack or wells with mudline suspension systems; and an updated schematic
of the full wellbore configuration. The schematic must be clearly
labeled and show all applicable top and bottom depths, locations and
sizes of all casings, cut casing or stubs, casing perforations, casing
rupture discs (indicate if burst or collapse and rating), cemented
intervals, cement plugs, mechanical plugs, perforated zones, completion
equipment, production and isolation packers, alternate completions,
tubing, landing nipples, subsurface safety devices, and any other
information required by the District Manager regarding the end of well
operations. The EOR must indicate the status of the well (completed,
temporarily abandoned, permanently abandoned, or drilling suspended) and
the date of the well status designation. The well status date is subject
to the following:
(1) For surface well operations and riserless subsea operations, the
operations end date is subject to the discretion of the District
Manager; and
(2) For subsea well operations, the operations end date is
considered to be the date the BOP is disconnected from the wellhead
unless otherwise specified by the District Manager.
(b) You must submit public information copies of Form BSEE-0125
according to Sec. 250.186(b).

Sec. 250.745 What other well records could I be required to submit?

The District Manager or Regional Supervisor may require you to
submit copies of any or all of the following well records:
(a) Well records as specified in Sec. 250.740;

[[Page 151]]

(b) Paleontological interpretations or reports identifying
microscopic fossils by depth and/or washed samples of drill cuttings
that you normally maintain for paleontological determinations. The
Regional Supervisor may issue a Notice to Lessees that sets forth the
manner, timeframe, and format for submitting this information;
(c) Service company reports on cementing, perforating, acidizing,
testing, or other similar services; or
(d) Other reports and records of operations.

Sec. 250.746 What are the recordkeeping requirements for casing, liner,
and BOP tests, and inspections of BOP systems and marine risers?

You must record the time, date, and results of all casing and liner
pressure tests. You must also record pressure tests, actuations, and
inspections of the BOP system, system components, and marine riser in
the daily report described in Sec. 250.740. In addition, you must:
(a) Record test pressures on pressure charts or digital recorders;
(b) Require your onsite lessee representative, designated rig or
contractor representative, and pump operator to sign and date the
pressure charts or digital recordings and daily reports as correct;
(c) Document on the daily report the sequential order of BOP and
auxiliary equipment testing and the pressure and duration of each test.
For subsea BOP systems, you must also record the closing times for
annular and ram BOPs. You may reference a BOP test plan if it is
available at the facility;
(d) Identify on the daily report the control station and pod used
during the test (identifying the pod does not apply to coiled tubing and
snubbing units);
(e) Identify on the daily report any problems or irregularities
observed during BOP system testing and record actions taken to remedy
the problems or irregularities. Any leaks associated with the BOP or
control system during testing must be documented in the WAR. If any
problems that cannot be resolved promptly are observed during testing,
operations must be suspended until the District Manager determines that
you may continue; and
(f) Retain all records, including pressure charts, daily reports,
and referenced documents pertaining to tests, actuations, and
inspections at the rig unit for the duration of the operation. After
completion of the operation, you must retain all the records listed in
this section for a period of 2 years at the rig unit. You must also
retain the records at the lessee's field office nearest the facility or
at another location available to BSEE. You must make all the records
available to BSEE upon request.

Subpart H_Oil and Gas Production Safety Systems

Source: 81 FR 60918, Sept. 7, 2016, unless otherwise noted.

General Requirements

Sec. 250.800 General.

(a) You must design, install, use, maintain, and test production
safety equipment in a manner to ensure the safety and protection of the
human, marine, and coastal environments. For production safety systems
operated in subfreezing climates, you must use equipment and procedures
that account for floating ice, icing, and other extreme environmental
conditions that may occur in the area. You must not commence production
until BSEE approves your production safety system application and you
have requested a preproduction inspection.
(b) For all new production systems on fixed leg platforms, you must
comply with API RP 14J (incorporated by reference as specified in Sec.
250.198);
(c) For all new floating production systems (FPSs) (e.g., column-
stabilized-units (CSUs); floating production, storage and offloading
facilities (FPSOs); tension-leg platforms (TLPs); and spars), you must:
(1) Comply with API RP 14J;
(2) Meet the production riser standards of API RP 2RD (incorporated
by reference as specified in Sec. 250.198), provided that you may not
install single bore production risers from floating production
facilities;
(3) Design all stationkeeping (i.e., anchoring and mooring) systems
for floating production facilities to meet

[[Page 152]]

the standards of API RP 2SK and API RP 2SM (both incorporated by
reference as specified in Sec. 250.198); and
(4) Design stationkeeping (i.e., anchoring and mooring) systems for
floating facilities to meet the structural requirements of Sec. Sec.
250.900 through 250.921.
(d) If there are any conflicts between the documents incorporated by
reference and the requirements of this subpart, you must follow the
requirements of this subpart.
(e) You may use alternate procedures or equipment during operations
after receiving approval from the District Manager. You must present
your proposed alternate procedures or equipment as required by Sec.
250.141.
(f) You may apply for a departure from the operating requirements of
this subpart as provided by Sec. 250.142. Your written request must
include a justification showing why the departure is necessary and
appropriate.

Sec. 250.801 Safety and pollution prevention equipment (SPPE) certification.

(a) SPPE equipment. In wells located on the OCS, you must install
only safety and pollution prevention equipment (SPPE) considered
certified under paragraph (b) of this section or accepted under
paragraph (c) of this section. BSEE considers the following equipment to
be types of SPPE:
(1) Surface safety valves (SSV) and actuators, including those
installed on injection wells capable of natural flow;
(2) Boarding shutdown valves (BSDV) and their actuators, as of
September 7, 2017. For subsea wells, the BSDV is the surface equivalent
of an SSV on a surface well;
(3) Underwater safety valves (USV) and actuators; and
(4) Subsurface safety valves (SSSV) and associated safety valve
locks and landing nipples.
(b) Certification of SPPE. SPPE that is manufactured and marked
pursuant to ANSI/API Spec. Q1 (incorporated by reference as specified in
Sec. 250.198), is considered as certified SPPE under this part. All
other SPPE is considered as not certified, unless approved in accordance
with paragraph (c) of this section.
(c) Accepting SPPE manufactured under other quality assurance
programs. BSEE may exercise its discretion to accept SPPE manufactured
under a quality assurance program other than ANSI/API Spec. Q1, provided
that the alternative quality assurance program is verified as equivalent
to API Spec. Q1 by an appropriately qualified entity and that the
operator submits a request to BSEE containing relevant information about
the alternative program and receives BSEE approval. In addition, an
operator may request that BSEE accept SPPE that is marked with a third-
party certification mark other than the API monogram. All requests under
this paragraph should be submitted to the Chief, Office of Offshore
Regulatory Programs; Bureau of Safety and Environmental Enforcement;
VAE-ORP; 45600 Woodland Road, Sterling, VA 20166.

Sec. 250.802 Requirements for SPPE.

(a) All SSVs, BSDVs, and USVs and their actuators must meet all of
the specifications contained in ANSI/API Spec. 6A and API Spec. 6AV1
(both incorporated by reference as specified in Sec. 250.198).
(b) All SSSVs and their actuators must meet all of the
specifications and recommended practices of ANSI/API Spec. 14A and ANSI/
API RP 14B, including all annexes (both incorporated by reference as
specified in Sec. 250.198). Subsurface-controlled SSSVs are not allowed
on subsea wells.
(c) Requirements derived from the documents incorporated in this
section for SSVs, BSDVs, USVs, and SSSVs and their actuators, include,
but are not limited to, the following:
(1) Each device must be designed to function and to close in the
most extreme conditions to which it may be exposed, including
temperature, pressure, flow rates, and environmental conditions. You
must have an independent third-party review and certify that each device
will function as designed under the conditions to which it may be
exposed. The independent third-party must have sufficient expertise and
experience to perform the review and certification.

[[Page 153]]

(2) All materials and parts must meet the original equipment
manufacturer specifications and acceptance criteria.
(3) The device must pass applicable validation tests and functional
tests performed by an API-licensed test agency.
(4) You must have requalification testing performed following
manufacture design changes.
(5) You must comply with and document all manufacturing,
traceability, quality control, and inspection requirements.
(6) You must follow specified installation, testing, and repair
protocols.
(7) You must use only qualified parts, procedures, and personnel to
repair or redress equipment.
(d) You must install and use SPPE according to the following table.

------------------------------------------------------------------------
If . . . Then . . .
------------------------------------------------------------------------
(1) You need to install any SPPE . . .. You must install SPPE that
conforms to Sec. 250.801.
(2) A non-certified SPPE is already in It may remain in service on
service . . .. that well.
(3) A non-certified SPPE requires You must replace it with SPPE
offsite repair, re-manufacturing, or that conforms to Sec.
any hot work such as welding . . .. 250.801.
------------------------------------------------------------------------

(e) You must retain all documentation related to the manufacture,
installation, testing, repair, redress, and performance of the SPPE
until 1 year after the date of decommissioning of the equipment.

Sec. 250.803 What SPPE failure reporting procedures must I follow?

(a) You must follow the failure reporting requirements contained in
section 10.20.7.4 of API Spec. 6A for SSVs, BSDVs, and USVs and section
7.10 of API Spec. 14A and Annex F of API RP 14B for SSSVs (all
incorporated by reference in Sec. 250.198). You must provide a written
notice of equipment failure to the Chief, Office of Offshore Regulatory
Programs or to the Chief's designee and to the manufacturer of such
equipment within 30 days after the discovery and identification of the
failure. A failure is any condition that prevents the equipment from
meeting the functional specification or purpose.
(b) You must ensure that an investigation and a failure analysis are
performed within 120 days of the failure to determine the cause of the
failure. If the investigation and analyses are performed by an entity
other than the manufacturer, you must ensure that manufacturer and the
Chief, Office of Offshore Regulatory Programs or the Chief's designee
receives a copy of the analysis report. You must also ensure that the
results of the investigation and any corrective action are documented in
the analysis report.
(c) If the equipment manufacturer notifies you that it has changed
the design of the equipment that failed or if you have changed operating
or repair procedures as a result of a failure, then you must, within 30
days of such changes, report the design change or modified procedures in
writing to the Chief, Office of Offshore Regulatory Programs or the
Chief's designee.
(d) Any notifications or reports submitted to the Chief, Office of
Offshore Regulatory Programs under paragraphs (a), (b), and (c) of this
section must be sent to: Bureau of Safety and Environmental Enforcement;
VAE-ORP, 45600 Woodland Road, Sterling, VA 20166.

Sec. 250.804 Additional requirements for subsurface safety valves (SSSVs)
and related equipment installed in high pressure high temperature (HPHT)
environments.

(a) If you plan to install SSSVs and related equipment in an HPHT
environment, you must submit detailed information with your Application
for Permit to Drill (APD) or Application for Permit to Modify (APM), and
Deepwater Operations Plan (DWOP) that demonstrates the SSSVs and related
equipment are capable of performing in the applicable HPHT environment.
Your detailed information must include the following:
(1) A discussion of the SSSVs' and related equipment's design
verification analyses;
(2) A discussion of the SSSVs' and related equipment's design
validation

[[Page 154]]

and functional testing processes and procedures used; and
(3) An explanation of why the analyses, processes, and procedures
ensure that the SSSVs and related equipment are fit-for-service in the
applicable HPHT environment.
(b) For this section, HPHT environment means when one or more of the
following well conditions exist:
(1) The completion of the well requires completion equipment or well
control equipment assigned a pressure rating greater than 15,000 psia or
a temperature rating greater than 350 degrees Fahrenheit;
(2) The maximum anticipated surface pressure or shut-in tubing
pressure is greater than 15,000 psia on the seafloor for a well with a
subsea wellhead or at the surface for a well with a surface wellhead; or
(3) The flowing temperature is equal to or greater than 350 degrees
Fahrenheit on the seafloor for a well with a subsea wellhead or at the
surface for a well with a surface wellhead.
(c) For this section, related equipment includes wellheads, tubing
heads, tubulars, packers, threaded connections, seals, seal assemblies,
production trees, chokes, well control equipment, and any other
equipment that will be exposed to the HPHT environment.

Sec. 250.805 Hydrogen sulfide.

(a) In zones known to contain hydrogen sulfide (H2S) or
in zones where the presence of H2S is unknown, as defined in
Sec. 250.490, you must conduct production operations in accordance with
that section and other relevant requirements of this subpart.
(b) You must receive approval through the DWOP process (Sec. Sec.
250.286 through 250.295) for production operations in HPHT environments
known to contain H2S or in HPHT environments where the
presence of H2S is unknown.

Sec. Sec. 250.806--250.809 [Reserved]

Surface and Subsurface Safety Systems--Dry Trees

Sec. 250.810 Dry tree subsurface safety devices--general.

For wells using dry trees or for which you intend to install dry
trees, you must equip all tubing installations open to hydrocarbon-
bearing zones with subsurface safety devices that will shut off the flow
from the well in the event of an emergency unless, after you submit a
request containing a justification, the District Manager determines the
well to be incapable of natural flow. You must install flow couplings
above and below the subsurface safety devices. These subsurface safety
devices include the following devices and any associated safety valve
lock and landing nipple:
(a) An SSSV, including either:
(1) A surface-controlled SSSV; or
(2) A subsurface-controlled SSSV.
(b) An injection valve.
(c) A tubing plug.
(d) A tubing/annular subsurface safety device.

Sec. 250.811 Specifications for SSSVs--dry trees.

All surface-controlled and subsurface-controlled SSSVs, safety valve
locks, and landing nipples installed in the OCS must conform to the
requirements specified in Sec. Sec. 250.801 through 250.803.

Sec. 250.812 Surface-controlled SSSVs--dry trees.

You must equip all tubing installations open to a hydrocarbon-
bearing zone that is capable of natural flow with a surface-controlled
SSSV, except as specified in Sec. Sec. 250.813, 250.815, and 250.816.
(a) The surface controls must be located on the site or at a BSEE-
approved remote location. You may request District Manager approval to
situate the surface controls at a remote location.
(b) You must equip dry tree wells not previously equipped with a
surface-controlled SSSV, and dry tree wells in which a surface-
controlled SSSV has

[[Page 155]]

been replaced with a subsurface-controlled SSSV, with a surface-
controlled SSSV when the tubing is first removed and reinstalled.

Sec. 250.813 Subsurface-controlled SSSVs.

You may submit an APM or a request to the District Manager for
approval to equip a dry tree well with a subsurface-controlled SSSV in
lieu of a surface-controlled SSSV, if the subsurface-controlled SSSV is
installed in a well equipped with a surface-controlled SSSV that has
become inoperable and cannot be repaired without removal and
reinstallation of the tubing. If you remove and reinstall the tubing,
you must equip the well with a surface-controlled SSSV.

Sec. 250.814 Design, installation, and operation of SSSVs--dry trees.

You must design, install, and operate (including repair, maintain,
and test) an SSSV to ensure its reliable operation.
(a) You must install the SSSV at a depth at least 100 feet below the
mudline within 2 days after production is established. When warranted by
conditions such as permafrost, unstable bottom conditions, hydrate
formation, or paraffin problems, the District Manager may approve an
alternate setting depth on a case-by-case basis.
(b) The well must not be open to flow while the SSSV is inoperable,
except when flowing the well is necessary for a particular operation
such as cutting paraffin or performing other routine operations as
defined in Sec. 250.601.
(c) Until the SSSV is installed, the well must be attended in the
immediate vicinity so that any necessary emergency actions can be taken
while the well is open to flow. During testing and inspection
procedures, the well must not be left unattended while open to
production unless you have installed a properly operating SSSV in the
well.
(d) You must design, install, maintain, inspect, repair, and test
all SSSVs in accordance with API RP 14B (incorporated by reference as
specified in Sec. 250.198). For additional SSSV testing requirements,
refer to Sec. 250.880.

Sec. 250.815 Subsurface safety devices in shut-in wells--dry trees.

(a) You must equip all new dry tree completions (perforated but not
placed on production) and completions that are shut-in for a period of 6
months with one of the following:
(1) A pump-through-type tubing plug;
(2) A surface-controlled SSSV, provided the surface control has been
rendered inoperative; or
(3) An injection valve capable of preventing backflow.
(b) When warranted by conditions such as permafrost, unstable bottom
conditions, hydrate formation, and paraffin problems, the District
Manager must approve the setting depth of the subsurface safety device
for a shut-in well on a case-by-case basis.

Sec. 250.816 Subsurface safety devices in injection wells--dry trees.

You must install a surface-controlled SSSV or an injection valve
capable of preventing backflow in all injection wells. This requirement
is not applicable if the District Manager determines that the well is
incapable of natural flow. You must verify the no-flow condition of the
well annually.

Sec. 250.817 Temporary removal of subsurface safety devices
for routine operations.

(a) You may remove a wireline- or pumpdown-retrievable subsurface
safety device without further authorization or notice, for a routine
operation that does not require BSEE approval of a Form BSEE-0124,
Application for Permit to Modify (APM). For a list of these routine
operations, see Sec. 250.601. The removal period must not exceed 15
days.
(b) Prior to removal, you must identify the well by placing a sign
on the wellhead stating that the subsurface safety device was removed.
You must note the removal of the subsurface safety device in the records
required by Sec. 250.890. If the master valve is open, you must ensure
that a trained person (see Sec. 250.891) is in the immediate vicinity
to attend the well and take any necessary emergency actions.
(c) You must monitor a platform well when a subsurface safety device
has been removed, but a person does not

[[Page 156]]

need to remain in the well-bay area continuously if the master valve is
closed. If the well is on a satellite structure, it must be attended by
a support vessel, or a pump-through plug must be installed in the tubing
at least 100 feet below the mudline and the master valve must be closed,
unless otherwise approved by the appropriate District Manager.
(d) You must not allow the well to flow while the subsurface safety
device is removed, except when it is necessary for the particular
operation for which the SSSV is removed. The provisions of this
paragraph are not applicable to the testing and inspection procedures
specified in Sec. 250.880.

Sec. 250.818 Additional safety equipment--dry trees.

(a) You must equip all tubing installations that have a wireline- or
pumpdown-retrievable subsurface safety device with a landing nipple,
with flow couplings or other protective equipment above and below it to
provide for the setting of the device.
(b) The control system for all surface-controlled SSSVs must be an
integral part of the platform emergency shutdown system (ESD).
(c) In addition to the activation of the ESD by manual action on the
platform, the system may be activated by a signal from a remote
location. Surface-controlled SSSVs must close in response to shut-in
signals from the ESD and in response to the fire loop or other fire
detection devices.

Sec. 250.819 Specification for surface safety valves (SSVs).

All wellhead SSVs and their actuators must conform to the
requirements specified in Sec. Sec. 250.801 through 250.803.

Sec. 250.820 Use of SSVs.

You must install, maintain, inspect, repair, and test all SSVs in
accordance with API RP 14H (incorporated by reference as specified in
Sec. 250.198). If any SSV does not operate properly, or if any gas and/
or liquid fluid flow is observed during the leakage test as described in
Sec. 250.880, then you must shut-in all sources to the SSV and repair
or replace the valve before resuming production.

Sec. 250.821 Emergency action and safety system shutdown--dry trees.

(a) In the event of an emergency, such as an impending National
Weather Service-named tropical storm or hurricane:
(1) Any well not yet equipped with a subsurface safety device and
that is capable of natural flow must have the subsurface safety device
properly installed as soon as possible, with due consideration being
given to personnel safety.
(2) You must shut-in (by closing the SSV and the surface-controlled
SSSV) the following types of wells:
(i) All oil wells, and
(ii) All gas wells requiring compression.
(b) Closure of the SSV must not exceed 45 seconds after automatic
detection of an abnormal condition or actuation of an ESD. The surface-
controlled SSSV must close within 2 minutes after the shut-in signal has
closed the SSV. The District Manager must approve any alternative
design-delayed closure time of greater than 2 minutes based on the
mechanical/production characteristics of the individual well.

Sec. Sec. 250.822--250.824 [Reserved]

Subsea and Subsurface Safety Systems--Subsea Trees

Sec. 250.825 Subsea tree subsurface safety devices--general.

(a) For wells using subsea (wet) trees or for which you intend to
install subsea trees, you must equip all tubing installations open to
hydrocarbon-bearing zones with subsurface safety devices that will shut
off the flow from the well in the event of an emergency. You must also
install flow couplings above and below the subsurface safety devices.
For instances where the well at issue is incapable of natural flow, you
may seek District Manager approval for using alternative procedures or
equipment, if you propose to use a subsea safety system that is not
capable of shutting off the flow from the

[[Page 157]]

well in the event of an emergency. Subsurface safety devices include the
following and any associated safety valve lock and landing nipple:
(1) A surface-controlled SSSV;
(2) An injection valve;
(3) A tubing plug; and
(4) A tubing/annular subsurface safety device.
(b) After installing the subsea tree, but before the rig or
installation vessel leaves the area, you must test all valves and
sensors to ensure that they are operating as designed and meet all the
conditions specified in this subpart.

Sec. 250.826 Specifications for SSSVs--subsea trees.

All SSSVs, safety valve locks, and landing nipples installed on the
OCS must conform to the requirements specified in Sec. Sec. 250.801
through 250.803 and any Deepwater Operations Plan (DWOP) required by
Sec. Sec. 250.286 through 250.295.

Sec. 250.827 Surface-controlled SSSVs--subsea trees.

Sec. 250.828 Design, installation, and operation of SSSVs--subsea trees.

You must design, install, and operate (including repair, maintain,
and test) an SSSV to ensure its reliable operation.
(a) You must install the SSSV at a depth at least 100 feet below the
mudline. When warranted by conditions, such as unstable bottom
conditions, permafrost, hydrate formation, or paraffin problems, the
District Manager may approve an alternate setting depth on a case-by-
case basis.
(b) The well must not be open to flow while an SSSV is inoperable,
unless specifically approved by the District Manager in an APM.
(c) You must design, install, maintain, inspect, repair, and test
all SSSVs in accordance with your Deepwater Operations Plan (DWOP) and
API RP 14B (incorporated by reference as specified in Sec. 250.198).
For additional SSSV testing requirements, refer to Sec. 250.880.

Sec. 250.829 Subsurface safety devices in shut-in wells--subsea trees.

(a) You must equip all new subsea tree completions (perforated but
not placed on production) and completions shut-in for a period of 6
months with one of the following:
(1) A pump-through-type tubing plug;
(2) An injection valve capable of preventing backflow; or
(3) A surface-controlled SSSV, provided the surface control has been
rendered inoperative. For purposes of this section, a surface-controlled
SSSV is considered inoperative if, for a direct hydraulic control
system, you have bled the hydraulics from the control line and have
isolated it from the hydraulic control pressure. If your controls employ
an electro-hydraulic control umbilical and the hydraulic control
pressure to the individual well cannot be isolated, a surface-controlled
SSSV is considered inoperative if you perform the following:
(i) Disable the control function of the surface-controlled SSSV
within the logic of the programmable logic controller which controls the
subsea well;
(ii) Place a pressure alarm high on the control line to the surface-
controlled SSSV of the subsea well; and
(iii) Close the USV and at least one other tree valve on the subsea
well.
(b) When warranted by conditions, such as unstable bottom
conditions, permafrost, hydrate formation, and paraffin problems, the
District Manager must approve the setting depth of the subsurface safety
device for a shut-in well on a case-by-case basis.

Sec. 250.830 Subsurface safety devices in injection wells--subsea trees.

[[Page 158]]

Sec. 250.831 Alteration or disconnection of subsea pipeline or umbilical.

If a necessary alteration or disconnection of the pipeline or
umbilical of any subsea well would affect your ability to monitor casing
pressure or to test any subsea valves or equipment, you must contact the
appropriate District Office at least 48 hours in advance and submit a
repair or replacement plan to conduct the required monitoring and
testing. You must not alter or disconnect until the repair or
replacement plan is approved.

Sec. 250.832 Additional safety equipment--subsea trees.

(a) You must equip all tubing installations that have a wireline- or
pump down-retrievable subsurface safety device installed after May 31,
1988, with a landing nipple, with flow couplings, or other protective
equipment above and below it to provide for the setting of the device.
(b) The control system for all surface-controlled SSSVs must be an
integral part of the platform ESD.
(c) In addition to the activation of the ESD by manual action on the
platform, the system may be activated by a signal from a remote
location.

Sec. 250.833 Specification for underwater safety valves (USVs).

All USVs, including those designated as primary or secondary, and
any alternate isolation valve (AIV) that acts as a USV, if applicable,
and their actuators, must conform to the requirements specified in
Sec. Sec. 250.801 through 250.803. A production master or wing valve
may qualify as a USV under API Spec. 6A and API Spec. 6AV1 (both
incorporated by reference as specified in Sec. 250.198).
(a) Primary USV (USV1). You must install and designate one USV on a
subsea tree as the USV1. The USV1 must be located upstream of the choke
valve. As provided in paragraph (b) of this section, you must inform
BSEE if the primary USV designation changes.
(b) Secondary USV (USV2). You may equip your tree with two or more
valves qualified to be designated as a USV, one of which may be
designated as the USV2. If the USV1 fails to operate properly or
exhibits a leakage rate greater than allowed in Sec. 250.880, you must
notify the appropriate District Office and designate the USV2 or another
qualified valve (e.g., an AIV) that meets all the requirements of this
subpart for USVs as the USV1. The USV2 must be located upstream of the
choke.

Sec. 250.834 Use of USVs.

You must install, maintain, inspect, repair, and test any valve
designated as the primary USV in accordance with this subpart, your DWOP
(as specified in Sec. Sec. 250.286 through 250.295), and API RP 14H
(incorporated by reference as specified in Sec. 250.198). For
additional USV testing requirements, refer to Sec. 250.880.

Sec. 250.835 Specification for all boarding shutdown valves (BSDVs)
associated with subsea systems.

You must install a BSDV on the pipeline boarding riser. All new
BSDVs and any BSDVs removed from service for remanufacturing or repair
and their actuators installed on the OCS must meet the requirements
specified in Sec. Sec. 250.801 through 250.803. In addition, you must:
(a) Ensure that the internal design pressure(s) of the pipeline(s),
riser(s), and BSDV(s) is fully rated for the maximum pressure of any
input source and complies with the design requirements set forth in
subpart J, unless BSEE approves an alternate design.
(b) Use a BSDV that is fire rated for 30 minutes, and is pressure
rated for the maximum allowable operating pressure (MAOP) approved in
your pipeline application.
(c) Locate the BSDV within 10 feet of the first point of access to
the boarding pipeline riser (i.e., within 10 feet of the edge of
platform if the BSDV is horizontal, or within 10 feet above the first
accessible working deck, excluding the boat landing and above the splash
zone, if the BSDV is vertical).
(d) Install a temperature safety element (TSE) and locate it within
5 feet of each BSDV.

Sec. 250.836 Use of BSDVs.

You must install, inspect, maintain, repair, and test all new BSDVs
and BSDVs that you remove from service

[[Page 159]]

for remanufacturing or repair in accordance with API RP 14H
(incorporated by reference as specified in Sec. 250.198) for SSVs. If
any BSDV does not operate properly or if any gas fluid and/or liquid
fluid flow is observed during the leakage test, as described in Sec.
250.880, you must shut-in all sources to the BSDV and immediately repair
or replace the valve.

Sec. 250.837 Emergency action and safety system shutdown--subsea trees.

(a) In the event of an emergency, such as an impending named
tropical storm or hurricane, you must shut-in all subsea wells unless
otherwise approved by the District Manager. A shut-in is defined as a
closed BSDV, USV, and surface-controlled SSSV.
(b) When operating a mobile offshore drilling unit (MODU) or other
type of workover vessel in an area with producing subsea wells, you
must:
(1) Suspend production from all such wells that could be affected by
a dropped object, including upstream wells that flow through the same
pipeline; or
(2) Establish direct, real-time communications between the MODU or
other type of workover vessel and the production facility control room
and prepare a plan to be submitted to the appropriate District Manager
for approval, as part of an Application for Permit to Drill (BSEE-0123)
or an Application for Permit to Modify (BSEE-0124), to shut-in any wells
that could be affected by a dropped object. If an object is dropped, the
driller (or other authorized rig floor personnel) must immediately
secure the well directly under the MODU or other type of workover vessel
using the ESD station near the driller's console while simultaneously
communicating with the platform to shut-in all affected wells. You must
also maintain without disruption, and continuously verify, communication
between the platform and the MODU or other type of workover vessel. If
communication is lost between the MODU or other type of workover vessel
and the platform for 20 minutes or more, you must shut-in all wells that
could be affected by a dropped object.
(c) In the event of an emergency, you must operate your production
system according to the valve closure times in the applicable tables in
Sec. Sec. 250.838 and 250.839 for the following conditions:
(1) Process upset. In the event an upset in the production process
train occurs downstream of the BSDV, you must close the BSDV in
accordance with the applicable tables in Sec. Sec. 250.838 and 250.839.
You may reopen the BSDV to blow down the pipeline to prevent hydrates,
provided you have secured the well(s) and ensured adequate protection.
(2) Pipeline pressure safety high and low (PSHL) sensor. In the
event that either a high or a low pressure condition is detected by a
PSHL sensor located upstream of the BSDV, you must secure the affected
well and pipeline, and all wells and pipelines associated with a dual or
multi pipeline system, by closing the BSDVs, USVs, and surface-
controlled SSSVs in accordance with the applicable tables in Sec. Sec.
250.838 and 250.839. You must obtain approval from the appropriate
District Manager to resume production in the unaffected pipeline(s) of a
dual or multi pipeline system. If the PSHL sensor activation was a false
alarm, you may return the wells to production without contacting the
appropriate District Manager.
(3) ESD/TSE (platform). In the event of an ESD activation that is
initiated because of a platform ESD or platform TSE not associated with
the BSDV, you must close the BSDV, USV, and surface-controlled SSSV in
accordance with the applicable tables in Sec. Sec. 250.838 and 250.839.
(4) Subsea ESD (platform) or BSDV TSE. In the event of an emergency
shutdown activation that is initiated by the host platform due to an
abnormal condition subsea, or a TSE associated with the BSDV, you must
close the BSDV, USV, and surface-controlled SSSV in accordance with the
applicable tables in Sec. Sec. 250.838 and 250.839.
(5) Subsea ESD (MODU). In the event of an ESD activation that is
initiated by a dropped object from a MODU or other type of workover
vessel, you must secure all wells in the proximity of the MODU or other
type of workover vessel by closing the USVs and surface-controlled SSSVs
in accordance with

[[Page 160]]

the applicable tables in Sec. Sec. 250.838 and 250.839. You must notify
the appropriate District Manager before resuming production.
(d) Following an ESD or fire, you must bleed your low pressure (LP)
and high pressure (HP) hydraulic systems in accordance with the
applicable tables in Sec. Sec. 250.838 and 250.839 to ensure that the
valves are locked out of service and cannot be reopened inadvertently.

Sec. 250.838 What are the maximum allowable valve closure times
and hydraulic bleeding requirements for an electro-hydraulic control system?

(a) If you have an electro-hydraulic control system, you must:
(1) Design the subsea control system to meet the valve closure times
listed in paragraphs (b) and (d) of this section or your approved DWOP;
and
(2) Verify the valve closure times upon installation. The District
Manager may require you to verify the closure time of the USV(s) through
visual authentication by diver or ROV.
(b) You must comply with the maximum allowable valve closure times
and hydraulic system bleeding requirements listed in the following table
or your approved DWOP as long as communication is maintained with the
platform or with the MODU or other type of workover vessel:

Valve Closure Timing, Electro-Hydraulic Control System
--------------------------------------------------------------------------------------------------------------------------------------------------------
Your LP Your HP
If you have the following. . Your pipeline Your USV1 must. Your USV2 must. Your alternate Your surface- hydraulic hydraulic
. BSDV must. . . . . . . isolation valve controlled SSSV system must. . system must. .
must. . . must. . . . .
--------------------------------------------------------------------------------------------------------------------------------------------------------
(1) Process upset............ Close within 45 [no requirements] [no [no [no
seconds after requirements]. requirements]. requirements].
sensor
activation.
(2) Pipeline PSHL............ Close within 45 Close one or more valves within 2 minutes and 45 Close within 60 [no Initiate
seconds after seconds after sensor activation. Close the minutes after requirements]. unrestricted
sensor designated USV1 within 20 minutes after sensor sensor bleed within
activation. activation. activation. If 24 hours after
you use a 60- sensor
minute manual activation.
resettable
timer, you may
continue to
reset the time
for closure up
to a maximum
of 24 hours
total.
(3) ESD/TSE (Platform)....... Close within 45 Close within 5 Close within 20 minutes after ESD Close within 20 Initiate Initiate
seconds after minutes after or sensor activation. minutes after unrestricted unrestricted
ESD or sensor ESD or sensor ESD or sensor bleed within bleed within
activation. activation. If activation. If 60 minutes 60 minutes
you use a 5- you use a 20- after ESD or after ESD or
minute minute manual sensor sensor
resettable resettable activation. If activation. If
timer, you may timer, you may you use a 60- you use a 60-
continue to continue to minute manual minute manual
reset the time reset the time resettable resettable
for closure up for closure up timer you must timer you must
to a maximum of to a maximum initiate initiate
20 minutes of 60 minutes unrestricted unrestricted
total. total. bleed within bleed within
24 hours. 24 hours.

[[Page 161]]

(4) Subsea ESD (Platform) or Close within 45 Close one or more valves within 2 minutes and 45 Close within 10 Initiate Initiate
BSDV TSE. seconds after seconds after ESD or sensor activation. Close all minutes after unrestricted unrestricted
ESD or sensor tree valves within 10 minutes after ESD or sensor ESD or sensor bleed within bleed within
activation. activation activation. 60 minutes 60 minutes
after ESD or after ESD or
sensor sensor
activation. activation.
(5) Subsea ESD (MODU or other [no Initiate valve closure immediately. You may allow for closure of the Initiate Initiate
type of workover vessel, requirements]. tree valves immediately prior to closure of the surface-controlled unrestricted unrestricted
Dropped object). SSSV if desired. bleed bleed within
immediately. 10 minutes
after ESD
activation.
--------------------------------------------------------------------------------------------------------------------------------------------------------

(c) If you have an electro-hydraulic control system and experience a
loss of communications (EH Loss of Comms), you must comply with the
following:
(1) If you can meet the EH Loss of Comms valve closure timing
conditions specified in the table in paragraph (d) of this section, you
must notify the appropriate District Office within 12 hours of detecting
the loss of communication.
(2) If you cannot meet the EH Loss of Comms valve closure timing
conditions specified in the table in paragraph (d) of this section, you
must notify the appropriate District Office immediately after detecting
the loss of communication. You must shut-in production by initiating a
bleed of the low pressure (LP) hydraulic system or the high pressure
(HP) hydraulic system within 120 minutes after loss of communication.
You must bleed the other hydraulic system within 180 minutes after loss
of communication.
(3) You must obtain approval from the appropriate District Manager
before continuing to produce after loss of communication when you cannot
meet the EH Loss of Comms valve closure times specified in the table in
paragraph (d) of this section. In your request, include an alternate
valve closure timing table that your system is able to achieve. The
appropriate District Manager may also approve an alternate hydraulic
bleed schedule to allow for hydrate mitigation and orderly shut-in.
(d) If you experience a loss of communications, you must comply with
the maximum allowable valve closure times and hydraulic system bleeding
requirements listed in the following table or your approved DWOP:

Valve Closure Timing, Electro-Hydraulic Control System With Loss of Communication
--------------------------------------------------------------------------------------------------------------------------------------------------------
Your LP Your HP
If you have the following. . Your pipeline Your USV1 must. Your USV2 must. Your alternate Your surface- hydraulic hydraulic
. BSDV must. . . . . . . isolation valve controlled SSSV system must. . system must. .
must. . . must. . . . .
--------------------------------------------------------------------------------------------------------------------------------------------------------
(1) Process upset............ Close within 45 [no requirements] [no [no [no
seconds after requirements]. requirements]. requirements].
sensor
activation.

[[Page 162]]

(2) Pipeline PSHL............ Close within 45 Initiate closure when LP hydraulic system is bled Initiate Initiate Initiate
seconds after (close valves within 5 minutes after sensor closure when unrestricted unrestricted
sensor activation). HP hydraulic bleed bleed within
activation. system is bled immediately, 24 hours after
(close within concurrent sensor
24 hours after with sensor activation.
sensor activation.
activation).
(3) ESD/TSE (Platform)....... Close within 45 Initiate closure when LP hydraulic system is bled Initiate Initiate Initiate
seconds after (close valves within 20 minutes after ESD or sensor closure when unrestricted unrestricted
ESD or sensor activation). HP hydraulic bleed bleed within
activation. system is bled concurrent 60 minutes
(close within with BSDV after ESD or
60 minutes closure (bleed sensor
after ESD or within 20 activation.
sensor minutes after
activation). ESD or sensor
activation).
(4) Subsea ESD (Platform) or Close within 45 Initiate closure when LP hydraulic system is bled Initiate Initiate Initiate
BSDV TSE. seconds after (close valves within 5 minutes after ESD or sensor closure when unrestricted unrestricted
ESD or sensor activation). HP hydraulic bleed bleed
activation. system is bled immediately. immediately,
(close within allowing for
20 minutes surface-
after ESD or controlled
sensor SSSV closure.
activation).
(5) Subsea ESD (MODU or other [no Initiate closure immediately. You may allow for closure of the tree Initiate Initiate
type of workover vessel), requirements]. valves immediately prior to closure of the surface-controlled SSSV unrestricted unrestricted
Dropped object. if desired. bleed bleed
immediately. immediately.
--------------------------------------------------------------------------------------------------------------------------------------------------------

Sec. 250.839 What are the maximum allowable valve closure times
and hydraulic bleeding requirements for a direct-hydraulic control system?

(a) If you have a direct-hydraulic control system, you must:
(1) Design the subsea control system to meet the valve closure times
listed in this section or your approved DWOP; and
(2) Verify the valve closure times upon installation. The District
Manager may require you to verify the closure time of the USV(s) through
visual authentication by diver or ROV.
(b) You must comply with the maximum allowable valve closure times
and hydraulic system bleeding requirements listed in the following table
or your approved DWOP:

Valve Closure Timing, Direct-Hydraulic Control System
--------------------------------------------------------------------------------------------------------------------------------------------------------
Your LP Your HP
If you have the following. . Your pipeline Your USV1 must. Your USV2 must. Your alternate Your surface- hydraulic hydraulic
. BSDV must. . . . . . . isolation valve controlled SSSV system must. . system must. .
must. . . must. . . . .
--------------------------------------------------------------------------------------------------------------------------------------------------------
(1) Process upset............ Close within 45 [no requirements] [no [no [no
seconds after requirements]. requirements]. requirements]
sensor
activation.

[[Page 163]]

(2) Flowline PSHL............ Close within 45 Close one or more valves within 2 minutes and 45 Close within 24 Complete bleed Complete bleed
seconds after seconds after sensor activation. Close the hours after of USV1, USV2, within 24
sensor designated USV1 within 20 minutes after sensor sensor and the AIV hours after
activation. activation. activation. within 20 sensor
minutes after activation.
sensor
activation.
(3) ESD/TSE (Platform)....... Close within 45 Close all valves within 20 minutes after ESD or Close within 60 Complete bleed Complete bleed
seconds after sensor activation. minutes after of USV1, USV2, within 60
ESD or sensor ESD or sensor and the AIV minutes after
activation. activation. within 20 ESD or sensor
minutes after activation.
ESD or sensor
activation.
(4) Subsea ESD (Platform) or Close within 45 Close one or more valves within 2 minutes and 45 Close within 10 Complete bleed Complete bleed
BSDV TSE. seconds after seconds after ESD or sensor activation. Close all minutes after of USV1, USV2, within 10
ESD or sensor tree valves within 10 minutes after ESD or sensor ESD or sensor and the AIV minutes after
activation. activation. activation. within 10 ESD or sensor
minutes after activation.
ESD or sensor
activation.
(5) Subsea ESD (MODU or other [no Initiate closure immediately. If desired, you may allow for closure Initiate Initiate
type of workover vessel), requirements]. of the tree valves immediately prior to closure of the surface- unrestricted unrestricted
Dropped object. controlled SSSV. bleed bleed
immediately. immediately.
--------------------------------------------------------------------------------------------------------------------------------------------------------

PRODUCTION SAFETY SYSTEMS

Sec. 250.840 Design, installation, and maintenance--general.

You must design, install, and maintain all production facilities and
equipment including, but not limited to, separators, treaters, pumps,
heat exchangers, fired components, wellhead injection lines,
compressors, headers, and flowlines in a manner that is efficient, safe,
and protects the environment.

Sec. 250.841 Platforms.

(a) You must protect all platform production facilities with a basic
and ancillary surface safety system designed, analyzed, installed,
tested, and maintained in operating condition in accordance with the
provisions of API RP 14C (incorporated by reference as specified in
Sec. 250.198). If you use processing components other than those for
which Safety Analysis Checklists are included in API RP 14C, you must
utilize the analysis technique and documentation specified in API RP 14C
to determine the effects and requirements of these components on the
safety system. Safety device requirements for pipelines are contained in
Sec. 250.1004.
(b) You must design, install, inspect, repair, test, and maintain in
operating condition all platform production process piping in accordance
with API RP 14E and API 570 (both incorporated by reference as specified
in Sec. 250.198). The District Manager may approve temporary repairs to
facility piping on a case-by-case basis for a period not to exceed 30
days.

[[Page 164]]

Sec. 250.842 Approval of safety systems design and installation features.

(a) Before you install or modify a production safety system, you
must submit a production safety system application to the District
Manager for approval. The application must include the information
prescribed in the following table:

------------------------------------------------------------------------
Details and/or additional
You must submit: requirements:
------------------------------------------------------------------------
(1) A schematic piping and Showing the following:
instrumentation diagram. (i) Well shut-in tubing
pressure;
(ii) Piping specification
breaks, piping sizes;
(iii) Pressure relief valve set
points;
(iv) Size, capacity, and design
working pressures of
separators, flare scrubbers,
heat exchangers, treaters,
storage tanks, compressors and
metering devices;
(v) Size, capacity, design
working pressures, and maximum
discharge pressure of
hydrocarbon-handling pumps;
(vi) Size, capacity, and design
working pressures of
hydrocarbon-handling vessels,
and chemical injection systems
handling a material having a
flash point below 100 degrees
Fahrenheit for a Class I
flammable liquid as described
in API RP 500 and 505 (both
incorporated by reference as
specified in Sec. 250.198);
and
(vii) Size and maximum
allowable working pressures as
determined in accordance with
API RP 14E (incorporated by
reference as specified in Sec.
250.198).
(2) A safety analysis flow diagram (API If processing components are
RP 14C, Appendix E) and the related used, other than those for
Safety Analysis Function Evaluation which Safety Analysis
(SAFE) chart (API RP 14C, subsection Checklists are included in API
4.3.3) (incorporated by reference as RP 14C, you must use the same
specified in Sec. 250.198). analysis technique and
documentation to determine the
effects and requirements of
these components upon the
safety system.
(3) Electrical system information, (i) A plan for each platform
including. deck and outlining all
classified areas. You must
classify areas according to
API RP 500 or API RP 505 (both
incorporated by reference as
specified in Sec. 250.198).
(ii) Identification of all
areas where potential ignition
sources, including non-
electrical ignition sources,
are to be installed showing:
(A) All major production
equipment, wells, and other
significant hydrocarbon
sources, and a description of
the type of decking, ceiling,
walls (e.g., grating or
solid), and firewalls and;
(B) The location of generators,
control rooms, panel boards,
major cabling/conduit routes,
and identification of the
primary wiring method (e.g.,
type cable, conduit, wire)
and;
(iii) One-line electrical
drawings of all electrical
systems including the safety
shutdown system. You must also
include a functional legend.
(4) Schematics of the fire and gas- Showing a functional block
detection systems. diagram of the detection
system, including the
electrical power supply and
also including the type,
location, and number of
detection sensors; the type
and kind of alarms, including
emergency equipment to be
activated; the method used for
detection; and the method and
frequency of calibration.
(5) The service fee listed in Sec. The fee you must pay will be
250.125. determined by the number of
components involved in the
review and approval process.
------------------------------------------------------------------------

(b) In the production safety system application, you must also
certify the following:
(1) That all electrical installations were designed according to API
RP 14F or API RP 14FZ, as applicable (incorporated by reference as
specified in Sec. 250.198);
(2) That the designs for the mechanical and electrical systems under
paragraph (a) of this section were reviewed, approved, and stamped by an
appropriate registered professional engineer(s). The registered
professional engineer must be registered in a State or Territory of the
United States and have sufficient expertise and experience to perform
the duties; and
(3) That a hazards analysis was performed in accordance with Sec.
250.1911 and API RP 14J (incorporated by reference as specified in Sec.
250.198), and

[[Page 165]]

that you have a hazards analysis program in place to assess potential
hazards during the operation of the facility.
(c) Before you begin production, you must certify, in a letter to
the District Manager, that the mechanical and electrical systems were
installed in accordance with the approved designs.
(d) Within 60 days after production commences, you must certify, in
a letter to the District Manager, that the as-built diagrams for the new
or modified production safety systems outlined in paragraphs (a)(1) and
(2) of this section and the piping and instrumentation diagrams are on
file and have been certified correct and stamped by an appropriate
registered professional engineer(s). The registered professional
engineer must be registered in a State or Territory in the United States
and have sufficient expertise and experience to perform the duties.
(e) All as-built diagrams outlined in paragraphs (a)(1) and (2) of
this section must be submitted to the District Manager within 60 days
after production commences.
(f) You must maintain information concerning the approved designs
and installation features of the production safety system at your
offshore field office nearest the OCS facility or at other locations
conveniently available to the District Manager. As-built piping and
instrumentation diagrams must be maintained at a secure onshore location
and readily available offshore. These documents must be made available
to BSEE upon request and be retained for the life of the facility. All
approvals are subject to field verifications.

Sec. Sec. 250.843-250.849 [Reserved]

Additional Production System Requirements

Sec. 250.850 Production system requirements--general.

You must comply with the production safety system requirements in
Sec. Sec. 250.851 through 250.872, in addition to the practices
contained in API RP 14C (incorporated by reference as specified in Sec.
250.198).

Sec. 250.851 Pressure vessels (including heat exchangers) and fired vessels.

(a) Pressure vessels (including heat exchangers) and fired vessels
supporting production operations must meet the requirements in the
following table:

------------------------------------------------------------------------
Applicable codes and
Item name requirements
------------------------------------------------------------------------
(1) Pressure and fired vessels......... (i) Must be designed,
fabricated, and code stamped
according to applicable
provisions of sections I, IV,
and VIII of the ANSI/ASME
Boiler and Pressure Vessel
Code (incorporated by
reference as specified in Sec.
250.198).
(ii) Must be repaired,
maintained, and inspected in
accordance with API 510
(incorporated by reference as
specified in Sec. 250.198).
(2) Existing uncoded pressure and fired Must be justified and approval
vessels (i) in use on November 7, obtained from the District
2016; (ii) with an operating pressure Manager for their continued
greater than 15 psig; and (iii) that use after March 1, 2018.
are not code stamped in accordance
with the ANSI/ASME Boiler and Pressure
Vessel Code.
(3) Pressure relief valves............. (i) Must be designed and
installed according to
applicable provisions of
sections I, IV, and VIII of
the ASME Boiler and Pressure
Vessel Code (incorporated by
reference as specified in Sec.
250.198).
(ii) Must conform to the valve
sizing and pressure-relieving
requirements specified in
these documents, but must be
set no higher than the maximum-
allowable working pressure of
the vessel (except for cases
where staggered set pressures
are required for
configurations using multiple
relief valves or redundant
valves installed and
designated for operator use
only).
(iii) Vents must be positioned
in such a way as to prevent
fluid from striking personnel
or ignition sources.
(4) Steam generators operating at less Must be equipped with a level
than 15 psig. safety low (LSL) sensor which
will shut off the fuel supply
when the water level drops
below the minimum safe level.

[[Page 166]]

(5) Steam generators operating at 15 (i) Must be equipped with a
psig or greater. level safety low (LSL) sensor
which will shut off the fuel
supply when the water level
drops below the minimum safe
level.
(ii) Must be equipped with a
water-feeding device that will
automatically control the
water level except when closed
loop systems are used for
steam generation.
------------------------------------------------------------------------

(b) Operating pressure ranges. You must use pressure recording
devices to establish the new operating pressure ranges of pressure
vessels at any time that the normalized system pressure changes by 50
psig or 5 percent. Once system pressure has stabilized, pressure
recording devices must be utilized to establish the new operating
pressure ranges. The pressure recording devices must document the
pressure range over time intervals that are no less than 4 hours and no
more than 30 days long. You must maintain the pressure recording
information you used to determine current operating pressure ranges at
your field office nearest the OCS facility or at another location
conveniently available to the District Manager for as long as the
information is valid.
(c) Pressure shut-in sensors must be set according to the following
table (initial set points for pressure sensors must be set utilizing
gauge readings and engineering design):

------------------------------------------------------------------------
Additional
Type of sensor Settings requirements
------------------------------------------------------------------------
(1) High pressure shut-in Must be set no Must also be set
sensor,. higher than 15 sufficiently below
percent or 5 psi (5 percent or 5 psi,
(whichever is whichever is
greater) above greater) the relief
the highest valve's set pressure
operating to assure that the
pressure of the pressure source is
vessel. shut-in before the
relief valve
activates.
(2) Low pressure shut-in Must be set no You must receive
sensor,. lower than 15 specific approval
percent or 5 psi from the District
(whichever is Manager for
greater) below activation limits on
the lowest pressure vessels
pressure in the that have a pressure
operating range. safety low (PSL)
sensor set less than
5 psi.
------------------------------------------------------------------------

Sec. 250.852 Flowlines/Headers.

(a) You must:
(1) Equip flowlines from wells with both PSH and PSL sensors. You
must locate these sensors in accordance with section A.1 of API RP 14C
(incorporated by reference as specified in Sec. 250.198).
(2) Use pressure recording devices to establish the new operating
pressure ranges of flowlines at any time when the normalized system
pressure changes by 50 psig or 5 percent, whichever is higher. The
pressure recording devices must document the pressure range over time
intervals that are no less than 4 hours and no more than 30 days long.
(3) Maintain the most recent pressure recording information you used
to determine operating pressure ranges at your field office nearest the
OCS facility or at another location conveniently available to the
District Manager for as long as the information is valid.
(b) Flowline shut-in sensors must meet the requirements in the
following table (initial set points for pressure sensors must be set
using gauge readings and engineering design):

------------------------------------------------------------------------
Type of flowline sensor Settings
------------------------------------------------------------------------
(1) PSH sensor,........................ Must be set no higher than 15
percent or 5 psi (whichever is
greater) above the highest
operating pressure of the
flowline. In all cases, the
PSH must be set sufficiently
below the maximum shut-in
wellhead pressure or the gas-
lift supply pressure to ensure
actuation of the SSV. Do not
set the PSH sensor above the
maximum allowable working
pressure of the flowline.

[[Page 167]]

(2) PSL sensor,........................ Must be set no lower than 15
percent or 5 psi (whichever is
greater) below the lowest
operating pressure of the
flowline in which it is
installed.
------------------------------------------------------------------------

(c) If a well flows directly to a pipeline before separation, the
flowline and valves from the well located upstream of and including the
header inlet valve(s) must have a working pressure equal to or greater
than the maximum shut-in pressure of the well unless the flowline is
protected by one of the following:
(1) A relief valve which vents into the platform flare scrubber or
some other location approved by the District Manager. You must design
the platform flare scrubber to handle, without liquid-hydrocarbon
carryover to the flare, the maximum-anticipated flow of hydrocarbons
that may be relieved to the vessel; or
(2) Two SSVs with independent PSH sensors connected to separate
relays and sensing points and installed with adequate volume upstream of
any block valve to allow sufficient time for the SSVs to close before
exceeding the maximum allowable working pressure. Each independent PSH
sensor must close both SSVs along with any associated flowline PSL
sensor. If the maximum shut-in pressure of a dry tree satellite well(s)
is greater than 1\1/2\ times the maximum allowable pressure of the
pipeline, a pressure safety valve (PSV) of sufficient size and relief
capacity to protect against any SSV leakage or fluid hammer effect may
be required by the District Manager. The PSV must be installed upstream
of the host platform boarding valve and vent into the platform flare
scrubber or some other location approved by the District Manager.
(d) If a well flows directly to the pipeline from a header without
prior separation, the header, the header inlet valves, and pipeline
isolation valve must have a working pressure equal to or greater than
the maximum shut-in pressure of the well unless the header is protected
by the safety devices as outlined in paragraph (c) of this section.
(e) If you are installing flowlines constructed of unbonded flexible
pipe on a floating platform, you must:
(1) Review the manufacturer's Design Methodology Verification Report
and the independent verification agent's (IVA's) certificate for the
design methodology contained in that report to ensure that the
manufacturer has complied with the requirements of API Spec. 17J
(incorporated by reference as specified in Sec. 250.198);
(2) Determine that the unbonded flexible pipe is suitable for its
intended purpose;
(3) Submit to the District Manager the manufacturer's design
specifications for the unbonded flexible pipe; and
(4) Submit to the District Manager a statement certifying that the
pipe is suitable for its intended use and that the manufacturer has
complied with the IVA requirements of API Spec. 17J (incorporated by
reference as specified in Sec. 250.198).
(f) Automatic pressure or flow regulating choking devices must not
prevent the normal functionality of the process safety system that
includes, but is not limited to, the flowline pressure safety devices
and the SSV.
(g) You may install a single flow safety valve (FSV) on the platform
to protect multiple subsea pipelines or wells that tie into a single
pipeline riser provided that you install an FSV for each riser on the
platform and test it in accordance with the criteria prescribed in Sec.
250.880(c)(2)(v).
(h) You may install a single PSHL sensor on the platform to protect
multiple subsea pipelines that tie into a single pipeline riser provided
that you install a PSHL sensor for each riser on the platform and locate
it upstream of the BSDV.

Sec. 250.853 Safety sensors.

You must ensure that:
(a) All shutdown devices, valves, and pressure sensors function in a
manual reset mode;

[[Page 168]]

(b) Sensors with integral automatic reset are equipped with an
appropriate device to override the automatic reset mode; and
(c) All pressure sensors are equipped to permit testing with an
external pressure source.

Sec. 250.854 Floating production units equipped with turrets
and turret-mounted systems.

(a) For floating production units equipped with an auto slew system,
you must integrate the auto slew control system with your process safety
system allowing for automatic shut-in of the production process,
including the sources (subsea wells, subsea pumps, etc.) and releasing
of the buoy. Your safety system must immediately initiate a process
system shut-in according to Sec. Sec. 250.838 and 250.839 and release
the buoy to prevent hydrocarbon discharge and damage to the subsea
infrastructure when the following are encountered:
(1) Your buoy is clamped,
(2) Your auto slew mode is activated, and
(3) You encounter a ship heading/position failure or an exceedance
of the rotational tolerances of the clamped buoy.
(b) For floating production units equipped with swivel stack
arrangements, you must equip the portion of the swivel stack containing
hydrocarbons with a leak detection system. Your leak detection system
must be tied into your production process surface safety system allowing
for automatic shut-in of the system. Upon seal system failure and
detection of a hydrocarbon leak, your surface safety system must
immediately initiate a process system shut-in according to Sec. Sec.
250.838 and 250.839.

Sec. 250.855 Emergency shutdown (ESD) system.

The ESD system must conform to the requirements of Appendix C,
section C1, of API RP 14C (incorporated by reference as specified in
Sec. 250.198), and the following:
(a) The manually operated ESD valve(s) must be quick-opening and
non-restricted to enable the rapid actuation of the shutdown system.
Electronic ESD stations must be wired as de-energize to trip circuits or
as supervised circuits. Because of the key role of the ESD system in the
platform safety system, all ESD components must be of high quality and
corrosion resistant and stations must be uniquely identified. Only ESD
stations at the boat landing may utilize a loop of breakable synthetic
tubing in lieu of a valve or electric switch. This breakable loop is not
required to be physically located on the boat landing, but must be
accessible from a vessel adjacent to or attached to the facility.
(b) You must maintain a schematic of the ESD that indicates the
control functions of all safety devices for the platforms on the
platform, at your field office nearest the OCS facility, or at another
location conveniently available to the District Manager, for the life of
the facility.

Sec. 250.856 Engines.

(a) Engine exhaust. You must equip all engine exhausts to comply
with the insulation and personnel protection requirements of API RP 14C,
section 4.2 (incorporated by reference as specified in Sec. 250.198).
You must equip exhaust piping from diesel engines with spark arresters.
(b) Diesel engine air intake. You must equip diesel engine air
intakes with a device to shut down the diesel engine in the event of
runaway (i.e., overspeed). You must equip diesel engines that are
continuously attended with either remotely operated manual or automatic
shutdown devices. You must equip diesel engines that are not
continuously attended with automatic shutdown devices. The following
diesel engines do not require a shutdown device: Engines for fire water
pumps; engines on emergency generators; engines that power BOP
accumulator systems; engines that power air supply for confined entry
personnel; temporary equipment on non-producing platforms; booster
engines whose purpose is to start larger engines; and engines that power
portable single cylinder rig washers.

[[Page 169]]

Sec. 250.857 Glycol dehydration units.

(a) You must install a pressure relief system or an adequate vent on
the glycol regenerator (reboiler) to prevent over pressurization. The
discharge of the relief valve must be vented in a nonhazardous manner.
(b) You must install the FSV on the dry glycol inlet to the glycol
contact tower as near as practical to the glycol contact tower.
(c) You must install the shutdown valve (SDV) on the wet glycol
outlet from the glycol contact tower as near as practical to the glycol
contact tower.

Sec. 250.858 Gas compressors.

(a) You must equip compressor installations with the following
protective equipment as required in API RP 14C, sections A.4 and A.8
(incorporated by reference as specified in Sec. 250.198).
(1) A pressure safety high (PSH) sensor, a pressure safety low (PSL)
sensor, a pressure safety valve (PSV), a level safety high (LSH) sensor,
and a level safety low (LSL) sensor to protect each interstage and
suction scrubber.
(2) A temperature safety high (TSH) sensor in the discharge piping
of each compressor cylinder or case discharge.
(3) You must design the PSH and PSL sensors and LSH controls
protecting compressor suction and interstage scrubbers to actuate
automatic SDVs located in each compressor suction and fuel gas line so
that the compressor unit and the associated vessels can be isolated from
all input sources. All automatic SDVs installed in compressor suction
and fuel gas piping must also be actuated by the shutdown of the prime
mover. Unless otherwise approved by the District Manager, gas-well gas
affected by the closure of the automatic SDV on the suction side of a
compressor must be diverted to the pipeline, diverted to a flare or vent
in accordance with Sec. Sec. 250.1160 or 250.1161, or shut-in at the
wellhead.
(4) You must install a blowdown valve on the discharge line of all
compressor installations that are 1,000 horsepower (746 kilowatts) or
greater.
(b) Once system pressure has stabilized, you must use pressure
recording devices to establish the new operating pressure ranges for
compressor discharge sensors whenever the normalized system pressure
changes by 50 psig or 5 percent, whichever is higher. The pressure
recording devices must document the pressure range over time intervals
that are no less than 4 hours and no more than 30 days long. You must
maintain the most recent pressure recording information that you used to
determine operating pressure ranges at your field office nearest the OCS
facility or at another location conveniently available to the District
Manager.
(c) Pressure shut-in sensors must be set according to the following
table (initial set points for pressure sensors must be set utilizing
gauge readings and engineering design):

[[Page 170]]

----------------------------------------------------------------------------------------------------------------
Type of sensor Settings Additional requirements
----------------------------------------------------------------------------------------------------------------
(1) PSH sensor, Must be set no higher than 15 percent or 5 psi Must also be set
(whichever is greater) above the highest sufficiently below (5
operating pressure of the discharge line and percent or 5 psi, whichever
sufficiently below the maximum discharge is greater) the set
pressure to ensure actuation of the suction SDV. pressure of the PSV to
assure that the pressure
source is shut-in before
the PSV activates.
(2) PSL sensor, Must be set no lower than 15 percent or 5 psi ............................
(whichever is greater) below the lowest
operating pressure of the discharge line in
which it is installed.
----------------------------------------------------------------------------------------------------------------

[[Page 171]]

Sec. 250.859 Firefighting systems.

(a) On fixed facilities, to protect all areas where production-
handling equipment is located, you must install firefighting systems
that meet the requirements of this paragraph. You must install a
firewater system consisting of rigid pipe with fire hose stations and/or
fixed firewater monitors to protect all areas where production-handling
equipment is located. Your firewater system must include installation of
a fixed water spray system in enclosed well-bay areas where hydrocarbon
vapors may accumulate.
(1) Your firewater system must conform to API RP 14G (incorporated
by reference as specified in Sec. 250.198).
(2) Fuel or power for firewater pump drivers must be available for
at least 30 minutes of run time during a platform shut-in. If necessary,
you must install an alternate fuel or power supply to provide for this
pump operating time unless the District Manager has approved an
alternate firefighting system. In addition:
(i) As of September 7, 2017, you must have equipped all new
firewater pump drivers with automatic starting capabilities upon
activation of the ESD, fusible loop, or other fire detection system.
(ii) For electric-driven firewater pump drivers, to provide for a
potential loss of primary power, you must install an automatic transfer
switch to cross over to an emergency power source in order to maintain
at least 30 minutes of run time. The emergency power source must be
reliable and have adequate capacity to carry the locked-rotor currents
of the fire pump motor and accessory equipment.
(iii) You must route power cables or conduits with wires installed
between the fire water pump drivers and the automatic transfer switch
away from hazardous-classified locations that can cause flame
impingement. Power cables or conduits with wires that connect to the
fire water pump drivers must be capable of maintaining circuit integrity
for not less than 30 minutes of flame impingement.
(3) You must post, in a prominent place on the facility, a diagram
of the firefighting system showing the location of all firefighting
equipment.
(4) For operations in subfreezing climates, you must furnish
evidence to the District Manager that the firefighting system is
suitable for those conditions.
(5) You must obtain approval from the District Manager before
installing any firefighting system.
(6) All firefighting equipment located on a facility must be in good
working order whether approved as the primary, secondary, or ancillary
firefighting system.
(b) On floating facilities, to protect all areas where production-
handling equipment is located, you must install a firewater system
consisting of rigid pipe with fire hose stations and/or fixed firewater
monitors. You must install a fixed water spray system in enclosed well-
bay areas where hydrocarbon vapors may accumulate. Your firewater system
must conform to the USCG requirements for firefighting systems on
floating facilities.
(c) Except as provided in paragraph (c)(1) and (2) of this section,
on fixed and floating facilities, if you are required to maintain a
firewater system and the system becomes inoperable, you must shut-in
your production operations while making the necessary repairs. For fixed
facilities only, you may continue your production operations on a
temporary basis while you make the necessary repairs, provided that:
(1) You request that the appropriate District Manager approve the
use of a chemical firefighting system on a temporary basis (for a period
up to 7 days) while you make the necessary repairs;
(2) If you are unable to complete repairs during the approved time
period because of circumstances beyond your control, the District
Manager may grant multiple extensions to your previously approved
request to use a chemical firefighting system for periods up to 7 days
each.

Sec. 250.860 Chemical firefighting system.

For fixed platforms:
(a) On minor unmanned platforms, you may use a U.S. Coast Guard type
and size rating ``B-II'' portable dry chemical unit (with a minimum UL
Rating (US) of 60-B:C) or a 30-pound portable dry chemical unit, in lieu
of a

[[Page 172]]

water system, as long as you ensure that the unit is available on the
platform when personnel are on board.
(1) A minor platform is a structure with zero to five completions
and no more than one item of production processing equipment.
(2) An unmanned platform is one that is not attended 24 hours a day
or one on which personnel are not quartered overnight.
(b) On major platforms and minor manned platforms, you may use a
firefighting system using chemicals-only in lieu of a water-based system
if the District Manager determines that the use of a chemical system
provides equivalent fire-protection control and would not increase the
risk to human safety.
(1) A major platform is a structure with either six or more
completions or zero to five completions with more than one item of
production processing equipment.
(2) A minor platform is a structure with zero to five completions
and no more than one item of production processing equipment.
(3) A manned platform is one that is attended 24 hours a day or one
on which personnel are quartered overnight.
(c) On major platforms and minor manned platforms, to obtain
approval to use a chemical-only fire prevention and control system in
lieu of a water system under paragraph (b) of this section, you must
submit to the District Manager:
(1) A justification for asserting that the use of a chemical system
provides equivalent fire-protection control. The justification must
address fire prevention, fire protection, fire control, and firefighting
on the platform; and
(2) A risk assessment demonstrating that a chemical-only system
would not increase the risk to human safety. You must provide the
following and any other important information in your risk assessment:

------------------------------------------------------------------------
For the use of a chemical
firefighting system on major and
minor manned platforms, you must Including . . .
provide the following in your risk
assessment . . .
------------------------------------------------------------------------
(i) Platform description.......... (A) The type and quantity of
hydrocarbons (i.e., natural gas,
oil) that are produced, handled,
stored, or processed at the
facility.
(B) The capacity of any tanks on the
facility that you use to store
either liquid hydrocarbons or other
flammable liquids.
(C) The total volume of flammable
liquids (other than produced
hydrocarbons) stored on the
facility in containers other than
bulk storage tanks. Include
flammable liquids stored in paint
lockers, storerooms, and drums.
(D) If the facility is manned,
provide the maximum number of
personnel on board and the
anticipated length of their stay.
(E) If the facility is unmanned,
provide the number of days per week
the facility will be visited, the
average length of time spent on the
facility per visit, the mode of
transportation, and whether or not
transportation will be available at
the facility while personnel are on
board.
(F) A diagram that depicts: quarters
location, production equipment
location, fire prevention and
control equipment location,
lifesaving appliances and equipment
location, and evacuation plan
escape routes from quarters and all
manned working spaces to primary
evacuation equipment.
(ii) Hazard assessment (facility (A) Identification of all likely
specific). fire initiation scenarios
(including those resulting from
maintenance and repair activities).
For each scenario, discuss its
potential severity and identify the
ignition and fuel sources.
(B) Estimates of the fire/radiant
heat exposure that personnel could
be subjected to. Show how you have
considered designated muster areas
and evacuation routes near fuel
sources and have verified proper
flare boom sizing for radiant heat
exposure.
(iii) Human factors assessment (A) Descriptions of the fire-related
(not facility specific). training your employees and
contractors have received. Include
details on the length of training,
whether the training was hands-on
or classroom, the training
frequency, and the topics covered
during the training.
(B) Descriptions of the training
your employees and contractors have
received in fire prevention,
control of ignition sources, and
control of fuel sources when the
facility is occupied.
(C) Descriptions of the instructions
and procedures you have given to
your employees and contractors on
the actions they should take if a
fire occurs. Include those
instructions and procedures
specific to evacuation. State how
you convey this information to your
employees and contractors on the
platform.
(iv) Evacuation assessment (A) A general discussion of your
(facility specific). evacuation plan. Identify your
muster areas (if applicable), both
the primary and secondary
evacuation routes, and the means of
evacuation for both.

[[Page 173]]

(B) Description of the type,
quantity, and location of
lifesaving appliances available on
the facility. Show how you have
ensured that lifesaving appliances
are located in the near vicinity of
the escape routes.
(C) Description of the types and
availability of support vessels,
whether the support vessels are
equipped with a fire monitor, and
the time needed for support vessels
to arrive at the facility.
(D) Estimates of the worst case time
needed for personnel to evacuate
the facility should a fire occur.
(v) Alternative protection (A) Discussion of the reasons you
assessment. are proposing to use an alternative
fire prevention and control system.
(B) Lists of the specific standards
used to design the system, locate
the equipment, and operate the
equipment/system.
(C) Description of the proposed
alternative fire prevention and
control system/equipment. Provide
details on the type, size, number,
and location of the prevention and
control equipment.
(D) Description of the testing,
inspection, and maintenance program
you will use to maintain the fire
prevention and control equipment in
an operable condition. Provide
specifics regarding the type of
inspection, the personnel who
conduct the inspections, the
inspection procedures, and
documentation and recordkeeping.
(vi) Conclusion................... A summary of your technical
evaluation showing that the
alternative system provides an
equivalent level of personnel
protection for the specific hazards
located on the facility.
------------------------------------------------------------------------

(d) On major or minor platforms, if BSEE has approved your request
to use a chemical-only fire suppressant system in lieu of a water system
under paragraphs (b) and (c) of this section, and if you make an
insignificant change to your platform subsequent to that approval, you
must document the change and maintain the documentation for the life of
the facility at either the facility or nearest field office for BSEE
review and/or inspection. Do not submit this documentation to the
District Manager. However, if you make a significant change to your
platform (e.g., placing a storage vessel with a capacity of 100 barrels
or more on the facility, adding production equipment), or if you plan to
man an unmanned platform temporarily, you must submit a new request for
approval, including an updated risk assessment if previously required,
to the appropriate District Manager. You must maintain, for the life of
the facility, the most recent documentation that you submitted to BSEE
at the facility or nearest field office.

Sec. 250.861 Foam firefighting systems.

When you install foam firefighting systems as part of a firefighting
system that protects production handling areas, you must:
(a) Annually conduct an inspection of the foam concentrates and
their tanks or storage containers for evidence of excessive sludging or
deterioration;
(b) Annually send samples of the foam concentrate to the
manufacturer or authorized representative for quality condition testing.
You must have the sample tested to determine the specific gravity, pH,
percentage of water dilution, and solid content. Based on these results,
the foam must be certified by an authorized representative of the
manufacturer as suitable firefighting foam consistent with the original
manufacturer's specifications. The certification document must be
readily accessible for field inspection. In lieu of sampling and
certification, you may choose to replace the total inventory of foam
with suitable new stock;
(c) Ensure that the quantity of concentrate meets design
requirements, and that tanks or containers are kept full, with space
allowed for expansion.

Sec. 250.862 Fire and gas-detection systems.

For production processing areas only:
(a) You must install fire (flame, heat, or smoke) sensors in all
enclosed classified areas. You must install gas sensors in all
inadequately ventilated, enclosed classified areas.
(1) Adequate ventilation is defined as ventilation that is
sufficient to prevent accumulation of significant quantities of vapor-
air mixture in concentrations

[[Page 174]]

over 25 percent of the lower explosive limit. An acceptable method of
providing adequate ventilation is one that provides a change of air
volume each 5 minutes or 1 cubic foot of air-volume flow per minute per
square foot of solid floor area, whichever is greater.
(2) Enclosed areas (e.g., buildings, living quarters, or doghouses)
are defined as those areas confined on more than 4 of their 6 possible
sides by walls, floors, or ceilings more restrictive to air flow than
grating or fixed open louvers and of sufficient size to allow entry of
personnel.
(3) A classified area is any area classified Class I, Group D,
Division 1 or 2, following the guidelines of API RP 500 (incorporated by
reference as specified in Sec. 250.198), or any area classified Class
I, Zone 0, Zone 1, or Zone 2, following the guidelines of API RP 505
(incorporated by reference as specified in Sec. 250.198).
(b) All detection systems must be capable of continuous monitoring.
Fire-detection systems and portions of combustible gas-detection systems
related to the higher gas-concentration levels must be of the manual-
reset type. Combustible gas-detection systems related to the lower gas-
concentration level may be of the automatic-reset type.
(c) A fuel-gas odorant or an automatic gas-detection and alarm
system is required in enclosed, continuously manned areas of the
facility which are provided with fuel gas. A gas detection system is not
required for living quarters and doghouses that do not contain a gas
source and that are not located in a classified area.
(d) The District Manager may require the installation and
maintenance of a gas detector or alarm in any potentially hazardous
area.
(e) Fire- and gas-detection systems must be an approved type, and
designed and installed in accordance with API RP 14C, API RP 14G, API RP
14F, API RP 14FZ, API RP 500, and API RP 505 (all incorporated by
reference as specified in Sec. 250.198), provided that, if compliance
with any provision of those standards would be in conflict with
applicable regulations of the U.S. Coast Guard, compliance with the U.S.
Coast Guard regulations controls.

Sec. 250.863 Electrical equipment.

You must design, install, and maintain electrical equipment and
systems in accordance with the requirements in Sec. 250.114.

Sec. 250.864 Erosion.

You must have a program of erosion control in effect for wells or
fields that have a history of sand production. The erosion-control
program may include sand probes, X-ray, ultrasonic, or other
satisfactory monitoring methods. You must maintain records for each
lease that indicate the wells that have erosion-control programs in
effect. You must also maintain the results of the programs for at least
2 years and make them available to BSEE upon request.

Sec. 250.865 Surface pumps.

(a) You must equip pump installations with the protective equipment
required in API RP 14C, Appendix A--A.7, Pumps (incorporated by
reference as specified in Sec. 250.198).
(b) You must use pressure recording devices to establish the new
operating pressure ranges for pump discharge sensors at any time when
the normalized system pressure changes by 50 psig or 5 percent,
whichever is higher. Once system pressure has stabilized, pressure
recording devices must be utilized to establish the new operating
pressure ranges. The pressure recording devices must document the
pressure range over time intervals that are no less than 4 hours and no
more than 30 days long. You must only maintain the most recent pressure
recording information that you used to determine operating pressure
ranges at your field office nearest the OCS facility or at another
location conveniently available to the District Manager.
(c) Pressure shut-in sensors must be set according to the following
table (initial set points for pressure sensors must be set utilizing
gauge readings and engineering design):

[[Page 175]]

------------------------------------------------------------------------
Additional
Type of sensor Settings requirements
------------------------------------------------------------------------
(1) PSH sensor............ Must be no higher Must be set
than 15 percent or 5 sufficiently below
psi (whichever is the maximum
greater) above the allowable working
highest operating pressure of the
pressure of the discharge piping.
discharge line. The PSH must also be
set at least 5
percent or 5 psi
(whichever is
greater) below the
set pressure of the
PSV to assure that
the pressure source
is shut-in before
the PSV activates.
(2) PSL sensor............ Must be set no lower
than 15 percent or 5
psi (whichever is
greater) below the
lowest operating
pressure of the
discharge line in
which it is
installed.
------------------------------------------------------------------------

(d) The PSL must be placed into service when the pump discharge
pressure has risen above the PSL sensing point, or within 45 seconds of
the pump coming into service, whichever is sooner.
(e) You may exclude the PSH and PSL sensors on small, low-volume
pumps such as chemical injection-type pumps. This is acceptable if such
a pump is used as a sump pump or transfer pump, has a discharge rating
of less than \1/2\ gallon per minute (gpm), discharges into piping that
is 1 inch or less in diameter, and terminates in piping that is 2 inches
or larger in diameter.
(f) You must install a TSE in the immediate vicinity of all pumps in
hydrocarbon service or those powered by platform fuel gas.
(g) The pump maximum discharge pressure must be determined using the
maximum possible suction pressure and the maximum power output of the
driver as appropriate for the pump type and service.

Sec. 250.866 Personnel safety equipment.

You must maintain all personnel safety equipment located on a
facility, whether required or not, in good working condition.

Sec. 250.867 Temporary quarters and temporary equipment.

(a) The District Manager must approve all temporary quarters to be
installed in production processing areas or other classified areas on
OCS facilities. You must equip such temporary quarters with all safety
devices required by API RP 14C, Appendix C (incorporated by reference as
specified in Sec. 250.198).
(b) The District Manager may require you to install a temporary
firewater system for temporary quarters in production processing areas
or other classified areas.
(c) Temporary equipment associated with the production process
system, including equipment used for well testing and/or well clean-up,
must be approved by the District Manager.

Sec. 250.868 Non-metallic piping.

On fixed OCS facilities, you may use non-metallic piping (such as
that made from polyvinyl chloride, chlorinated polyvinyl chloride, and
reinforced fiberglass) only in accordance with the requirements of Sec.
250.841(b).

Sec. 250.869 General platform operations.

(a) Surface or subsurface safety devices must not be bypassed or
blocked out of service unless they are temporarily out of service for
startup, maintenance, or testing. You may take only the minimum number
of safety devices out of service. Personnel must monitor the bypassed or
blocked-out functions until the safety devices are placed back in
service. Any surface or subsurface safety device which is temporarily
out of service must be flagged. A designated visual indicator must be
used to identify the bypassed safety device. You must follow the
monitoring procedures as follows:
(1) If you are using a non-computer-based system, meaning your
safety system operates primarily with pneumatic supply or non-
programmable electrical systems, you must monitor bypassed safety
devices by positioning monitoring personnel at either the control panel
for the bypassed safety device, or at the bypassed safety device, or at
the

[[Page 176]]

component that the bypassed safety device would be monitoring when in
service. You must also ensure that monitoring personnel are able to view
all relevant essential operating conditions until all bypassed safety
devices are placed back in service and are able to initiate shut-in
action in the event of an abnormal condition.
(2) If you are using a computer-based technology system, meaning a
computer-controlled electronic safety system such as supervisory control
and data acquisition and remote terminal units, you must monitor
bypassed safety devices by maintaining instantaneous communications at
all times among remote monitoring personnel and the personnel performing
maintenance, testing, or startup. Until all bypassed safety devices are
placed back in service, you must also position monitoring personnel at a
designated control station that is capable of the following:
(i) Displaying all relevant essential operating conditions that
affect the bypassed safety device, well, pipeline, and process
component. If electronic display of all relevant essential conditions is
not possible, you must have field personnel monitoring the level gauges
(sight glass) and pressure gauges in order to know the current operating
conditions. You must be in communication with all field personnel
monitoring the gauges;
(ii) Controlling the production process equipment and the entire
safety system;
(iii) Displaying a visual indicator when safety devices are placed
in the bypassed mode; and
(iv) Upon command, overriding the bypassed safety device and
initiating shut-in action in the event of an abnormal condition.
(3) You must not bypass for startup any element of the emergency
support system or other support system required by API RP 14C, Appendix
C (incorporated by reference as specified in Sec. 250.198) without
first receiving BSEE approval to depart from this operating procedure.
These systems include, but are not limited to:
(i) The ESD system to provide a method to manually initiate platform
shutdown by personnel observing abnormal conditions or undesirable
events. You do not have to receive approval from the District Manager
for manual reset and/or initial charging of the system;
(ii) The fire loop system to sense the heat of a fire and initiate
platform shutdown, and other fire detection devices (flame, thermal, and
smoke) that are used to enhance fire detection capability. You do not
have to receive approval from the District Manager for manual reset and/
or initial charging of the system;
(iii) The combustible gas detection system to sense the presence of
hydrocarbons and initiate alarms and platform shutdown before gas
concentrations reach the lower explosive limit;
(iv) Adequate ventilation;
(v) The containment system to collect escaped liquid hydrocarbons
and initiate platform shutdown;
(vi) Subsurface safety valves, including those that are self-
actuated (subsurface-controlled SSSVs) or those that are activated by an
ESD system and/or a fire loop (surface-controlled SSSV). You do not have
to receive approval from the District Manager for routine operations in
accordance with Sec. 250.817;
(vii) The pneumatic supply system; and
(viii) The system for discharging gas to the atmosphere.
(4) In instances where components of the ESD, as listed in paragraph
(a)(3) of this section, are bypassed for maintenance, precautions must
be taken to provide the equivalent level of protection that existed
prior to the bypass.
(b) When wells are disconnected from producing facilities and blind
flanged, or equipped with a tubing plug, or the master valves have been
locked closed, you are not required to comply with the provisions of API
RP 14C (incorporated by reference as specified in Sec. 250.198) or this
regulation concerning the following:
(1) Automatic fail-close SSVs on wellhead assemblies, and
(2) The PSH and PSL sensors in flowlines from wells.
(c) When pressure or atmospheric vessels are isolated from
production facilities (e.g., inlet valve locked closed

[[Page 177]]

or inlet blind-flanged) and are to remain isolated for an extended
period of time, safety device testing in accordance with API RP 14C
(incorporated by reference as specified in Sec. 250.198), or this
subpart is not required, with the exception of the PSV, unless the
vessel is open to the atmosphere.
(d) All open-ended lines connected to producing facilities and wells
must be plugged or blind-flanged, except those lines designed to be
open-ended such as flare or vent lines.
(e) On all new production safety system installations, component
process control devices and component safety devices must not be
installed utilizing the same sensing points.
(f) All pneumatic control panels and computer based control stations
must be labeled according to API RP 14C nomenclature.

Sec. 250.870 Time delays on pressure safety low (PSL) sensors.

(a) You may apply any or all of the industry standard Class B, Class
C, or Class B/C logic to all applicable PSL sensors installed on process
equipment, as long as the time delay does not exceed 45 seconds. Use of
a PSL sensor with a time delay greater than 45 seconds requires BSEE
approval in accordance with Sec. 250.141. You must document on your
field test records any use of a PSL sensor with a time delay greater
than 45 seconds. For purposes of this section, PSL sensors are
categorized as follows:
(1) Class B safety devices have logic that allows for the PSL
sensors to be bypassed for a fixed time period (typically less than 15
seconds, but not more than 45 seconds). Examples include sensors used in
conjunction with the design of pump and compressor panels such as PSL
sensors, lubricator no-flows, and high-water jacket temperature
shutdowns.
(2) Class C safety devices have logic that allows for the PSL
sensors to be bypassed until the component comes into full service
(i.e., the time at which the startup pressure equals or exceeds the set
pressure of the PSL sensor, the system reaches a stabilized pressure,
and the PSL sensor clears).
(3) Class B/C safety devices have logic that allows for the PSL
sensors to incorporate a combination of Class B and Class C circuitry.
These devices are used to ensure that the PSL sensors are not
unnecessarily bypassed during startup and idle operations, (e.g., Class
B/C bypass circuitry activates when a pump is shut down during normal
operations). The PSL sensor remains bypassed until the pump's start
circuitry is activated and either:
(i) The Class B timer expires no later than 45 seconds from start
activation, or
(ii) The Class C bypass is initiated until the pump builds up
pressure above the PSL sensor set point and the PSL sensor comes into
full service.
(b) If you do not install time delay circuitry that bypasses
activation of PSL sensor shutdown logic for a specified time period on
process and product transport equipment during startup and idle
operations, you must manually bypass (pin out or disengage) the PSL
sensor, with a time delay not to exceed 45 seconds.

Sec. 250.871 Welding and burning practices and procedures.

All welding, burning, and hot-tapping activities must be conducted
according to the specific requirements in Sec. 250.113.

Sec. 250.872 Atmospheric vessels.

(a) You must equip atmospheric vessels used to process and/or store
liquid hydrocarbons or other Class I liquids as described in API RP 500
or 505 (both incorporated by reference as specified in Sec. 250.198)
with protective equipment identified in API RP 14C, section A.5
(incorporated by reference as specified in Sec. 250.198). Transport
tanks approved by the U.S. Department of Transportation, that are sealed
and not connected via interconnected piping to the production process
train and that are used only for storage of refined liquid hydrocarbons
or Class I liquids, are not required to be equipped with the protective
equipment identified in API RP 14C, section A.5.
(b) You must ensure that all atmospheric vessels are designed and
maintained to ensure the proper working conditions for LSH sensors. The
LSH

[[Page 178]]

sensor bridle must be designed to prevent different density fluids from
impacting sensor functionality. For atmospheric vessels that have oil
buckets, the LSH sensor must be installed to sense the level in the oil
bucket.
(c) You must ensure that all flame arrestors are maintained to
ensure proper design function (installation of a system to allow for
ease of inspection should be considered).

Sec. 250.873 Subsea gas lift requirements.

If you choose to install a subsea gas lift system, you must design
your system as approved in your DWOP or as follows:
(a) Design the gas lift supply pipeline in accordance with API RP
14C (incorporated by reference as specified in Sec. 250.198) for the
gas lift supply system located on the platform.
(b) Meet the applicable requirements in the following table:

[[Page 179]]

--------------------------------------------------------------------------------------------------------------------------------------------------------
Then you must install a
---------------------------------------------------------------------------------------------
API Spec 6A and API Spec
If your subsea gas lift system 6AV1 (both incorporated API Spec 6A and API
introduces the lift gas to the . by reference as specified FSV on the gas-lift PSHL on the gas-lift Spec 6AV1 manual In addition, you must
. . in Sec. 250.198) gas- supply pipeline . . supply . . . isolation valve . .
lift shutdown valve . .
(GLSDV), and . . .
--------------------------------------------------------------------------------------------------------------------------------------------------------
(1) Subsea pipelines, pipeline Meet all of the on the platform pipeline on the downstream (out (i) Ensure that the MAOP
risers, or manifolds via an requirements for the upstream (in-board) platform downstream board) of the PSHL of a subsea gas lift
external gas lift pipeline or BSDV described in Sec. of the GLSDV. (out board) of the and above the supply pipeline is
umbilical. Sec. 250.835 and GLSDV. waterline. This equal to the MAOP of
250.836 on the gas-lift valve does not have the production
supply pipeline. Locate to be actuated. pipeline.
the GLSDV within 10 feet (ii) Install an actuated
of the first point of fail-safe close gas-
access to the gas-lift lift isolation valve
riser or topsides (GLIV) located at the
umbilical termination point of intersection
assembly (TUTA) (i.e., between the gas lift
within 10 feet of the supply pipeline and the
edge of the platform if production pipeline,
the GLSDV is horizontal, pipeline riser, or
or within 10 feet above manifold.
the first accessible (iii) Install the GLIV
working deck, excluding downstream of the
the boat landing and underwater safety
above the splash zone, valve(s) (USV) and/or
if the GLSDV is in the AIV(s).
vertical run of a riser,
or within 10 feet of the
TUTA if using an
umbilical).
(2) Subsea well(s) through the Meet all of the on the platform pipeline on the downstream (out (i) Install an actuated,
casing string via an external requirements for the upstream (in-board) platform down- board) of the PSHL fail-safe-closed GLIV
gas lift pipeline or umbilical. GLSDV described in Sec. of the GLSDV. stream (out board) and above the on the gas lift supply
Sec. 250.835 and of the GLSDV. waterline. This pipeline near the
250.836 on the gas-lift valve does not have wellhead to provide the
supply pipeline. Locate to be actuated.. dual function of
the GLSDV within 10 feet containing annular
of the first point of pressure and shutting
access to the gas-lift off the gas lift supply
riser or topsides gas.
umbilical termination (ii) If your subsea tree
assembly (TUTA) (i.e., or tubing head is
within 10 feet of the equipped with an
edge of the platform if annulus master valve
the GLSDV is horizontal, (AMV) or an annulus
or within 10 feet above wing valve (AWV), one
the first accessible of these may be
working deck, excluding designated as the GLIV.
the boat landing and (iii) Consider
above the splash zone, installing the GLIV
if the GLSDV is in the external to the subsea
vertical run of a riser, tree to facilitate
or within 10 feet of the repair and or
TUTA if using an replacement if
umbilical). necessary.

[[Page 180]]

(3) Pipeline risers via a gas- Meet all of the upstream (in-board) flowline upstream downstream (out (i) Ensure that the gas-
lift line contained within the requirements for the of the GLSDV. (in-board) of the board) of the GLSDV. lift supply flowline
pipeline riser. GLSDV described in Sec. FSV. from the gas-lift
Sec. 250.835(a), (b), compressor to the GLSDV
and (d) and 250.836 on is pressure-rated for
the gas-lift supply the MAOP of the
pipeline. Attach the pipeline riser.
GLSDV by flanged (ii) Ensure that any
connection directly to surface equipment
the API Spec. 6A associated with the gas-
component used to lift system is rated
suspend and seal the gas- for the MAOP of the
lift line contained pipeline riser.
within the production (iii) Ensure that the
riser. To facilitate the gas-lift compressor
repair or replacement of discharge pressure
the GLSDV or production never exceeds the MAOP
riser BSDV, you may of the pipeline riser.
install a manual (iv) Suspend and seal
isolation valve between the gas-lift flowline
the GLSDV and the API contained within the
Spec. 6A component used production riser in a
to suspend and seal the flanged API Spec. 6A
gas-lift line contained component such as an
within the production API Spec. 6A tubing
riser, or outboard of head and tubing hanger
the production riser or a component
BSDV and inboard of the designed, constructed,
API Spec. 6A component tested, and installed
used to suspend and seal to the requirements of
the gas-lift line API Spec. 6A.
contained within the (v) Ensure that all
production riser. potential leak paths
upstream or near the
production riser BSDV
on the platform provide
the same level of
safety and
environmental
protection as the
production riser BSDV.
(vi) Ensure that this
complete assembly is
fire-rated for 30
minutes.
--------------------------------------------------------------------------------------------------------------------------------------------------------

[[Page 181]]

(c) Follow the valve closure times and hydraulic bleed requirements
according to your approved DWOP for the following:
(1) Electro-hydraulic control system with gas lift,
(2) Electro-hydraulic control system with gas lift with loss of
communications,
(3) Direct-hydraulic control system with gas lift.
(d) Follow the gas lift system valve testing requirements according
to the following table:

[[Page 182]]

----------------------------------------------------------------------------------------------------------------
Type of gas lift system Valve Allowable leakage rate Testing frequency
----------------------------------------------------------------------------------------------------------------
(1) Gas lifting a subsea pipeline, GLSDV Zero leakage............... Monthly, not to exceed 6
pipeline riser, or manifold via an weeks.
external gas lift pipeline.
GLIV N/A........................ Function tested quarterly,
not to exceed 120 days.
(2) Gas lifting a subsea well GLSDV Zero leakage............... Monthly, not to exceed 6
through the casing string via an weeks.
external gas lift pipeline.
GLIV 400 cc per minute of liquid Function tested quarterly,
or 15 scf per minute of not to exceed 120 days
gas..
(3) Gas lifting the pipeline riser GLSDV Zero leakage............... Monthly, not to exceed 6
via a gas lift line contained weeks.
within the pipeline riser.
----------------------------------------------------------------------------------------------------------------

[[Page 183]]

Sec. 250.874 Subsea water injection systems.

If you choose to install a subsea water injection system, your
system must comply with your approved DWOP, which must meet the
following minimum requirements:
(a) Adhere to the water injection requirements described in API RP
14C (incorporated by reference as specified in Sec. 250.198) for the
water injection equipment located on the platform. In accordance with
Sec. 250.830, either a surface-controlled SSSV or a water injection
valve (WIV) that is self-activated and not controlled by emergency shut-
down (ESD) or sensor activation must be installed in a subsea water
injection well.
(b) Equip a water injection pipeline with a surface FSV and water
injection shutdown valve (WISDV) on the surface facility.
(c) Install a PSHL sensor upstream (in-board) of the FSV and WISDV.
(d) Use subsea tree(s), wellhead(s), connector(s), and tree valves,
and surface-controlled SSSV or WIV associated with a water injection
system that are rated for the maximum anticipated injection pressure.
(e) Consider the effects of hydrogen sulfide (H2S) when designing
your water flood system, as required by Sec. 250.805.
(f) Follow the valve closure times and hydraulic bleed requirements
according to your approved DWOP for the following:
(1) Electro-hydraulic control system with water injection,
(2) Electro-hydraulic control system with water injection with loss
of communications, and
(3) Direct-hydraulic control system with water injection.
(g) Comply with the following injection valve testing requirements:
(1) You must test your injection valves as provided in the following
table:

------------------------------------------------------------------------
Allowable leakage
Valve rate Testing frequency
------------------------------------------------------------------------
(i) WISDV....................... Zero leakage...... Monthly, not to
exceed 6 weeks
between tests.
(ii) Surface-controlled SSSV or 400 cc per minute Semiannually, not
WIV. of liquid or. to exceed
15 scf per minute 6 calendar months
of gas. between tests.
------------------------------------------------------------------------

(2) If a designated USV on a water injection well fails the
applicable test under Sec. 250.880(c)(4)(ii), you must notify the
appropriate District Manager and request approval to designate another
API Spec 6A and API Spec. 6AV1 (both incorporated by reference as
specified in Sec. 250.198) certified subsea valve as your USV.
(3) If a USV on a water injection well fails the test and the
surface-controlled SSSV or WIV cannot be tested as required under
(g)(1)(ii) of this section because of low reservoir pressure, you must
submit a request to the appropriate District Manager with an alternative
plan that ensures subsea shutdown capabilities.
(h) If you experience a loss of communications during water
injection operations, you must comply with the following:
(1) Notify the appropriate District Manager within 12 hours after
detecting loss of communication; and
(2) Obtain approval from the appropriate District Manager to
continue to inject during the loss of communication.

Sec. 250.875 Subsea pump systems.

If you choose to install a subsea pump system, your system must
comply with your approved DWOP, which must meet the following minimum
requirements:
(a) Include the installation of an isolation valve at the inlet of
your subsea pump module.
(b) Include a PSHL sensor upstream of the BSDV, if the maximum
possible discharge pressure of the subsea pump operating in a dead head
condition (that is the maximum shut-in tubing pressure at the pump inlet
and a closed BSDV) is less than the MAOP of the associated pipeline.
(c) If the maximum possible discharge pressure of the subsea pump
operating in a dead head situation could

[[Page 184]]

be greater than the MAOP of the pipeline:
(1) Include, at minimum, 2 independent functioning PSHL sensors
upstream of the subsea pump and 2 independent functioning PSHL sensors
downstream of the pump, that:
(i) Are operational when the subsea pump is in service; and
(ii) Will, when activated, shut down the subsea pump, the subsea
inlet isolation valve, and either the designated USV1, the USV2, or the
alternate isolation valve.
(iii) If more than 2 PSHL sensors are installed both upstream and
downstream of the subsea pump for operational flexibility, then 2 out of
3 voting logic may be implemented in which the subsea pump remains
operational provided a minimum of 2 independent PSHL sensors are
functional both upstream and downstream of the pump.
(2) Interlock the subsea pump motor with the BSDV to ensure that the
pump cannot start or operate when the BSDV is closed, incorporate at a
minimum the following permissive signals into the control system for
your subsea pump, and ensure that the subsea pump is not able to be
started or re-started unless:
(i) The BSDV is open;
(ii) All automated valves downstream of the subsea pump are open;
(iii) The upstream subsea pump isolation valve is open; and
(iv) All parameters associated with the subsea pump operation (e.g.,
pump temperature high, pump vibration high, pump suction pressure high,
pump discharge pressure high, pump suction flow low) must be cleared
(i.e., within operational limits) or continuously monitored by personnel
who observe visual indicators displayed at a designated control station
and have the capability to initiate shut-in action in the event of an
abnormal condition.
(3) Monitor the separator for seawater.
(4) Ensure that the subsea pump systems are controlled by an
electro-hydraulic control system.
(d) Follow the valve closure times and hydraulic bleed requirements
according to your approved DWOP for the following:
(1) Electro-hydraulic control system with a subsea pump;
(2) A loss of communication with the subsea well(s) and not a loss
of communication with the subsea pump control system without an ESD or
sensor activation;
(3) A loss of communication with the subsea pump control system, and
not a loss of communication with the subsea well(s);
(4) A loss of communication with the subsea well(s) and the subsea
pump control system.
(e) For subsea pump testing:
(1) Perform a complete subsea pump function test, including full
shutdown, after any intervention or changes to the software and
equipment affecting the subsea pump; and
(2) Test the subsea pump shutdown, including PSHL sensors both
upstream and downstream of the pump, each quarter (not to exceed 120
days between tests). This testing may be performed concurrently with the
ESD function test required by Sec. 250.880(c)(4)(v).

Sec. 250.876 Fired and exhaust heated components.

No later than September 7, 2018, and at least once every 5 years
thereafter, you must have a qualified third-party remove and inspect,
and then you must repair or replace, as needed, the fire tube for tube-
type heaters that are equipped with either automatically controlled
natural or forced draft burners installed in either atmospheric or
pressure vessels that heat hydrocarbons and/or glycol. If removal and
inspection indicates tube-type heater deficiencies, you must complete
and document repairs or replacements. You must document the inspection
results, retain such documentation for at least 5 years, and make the
documentation available to BSEE upon request.

Sec. Sec. 250.877--250.879 [Reserved]

Safety Device Testing

Sec. 250.880 Production safety system testing.

(a) Notification. You must:
(1) Notify the District Manager at least 72 hours before commencing
production, so that BSEE may conduct a

[[Page 185]]

preproduction inspection of the integrated safety system.
(2) Notify the District Manager upon commencement of production so
that BSEE may conduct a complete inspection.
(3) Notify the District Manager and receive BSEE approval before you
perform any subsea intervention that modifies the existing subsea
infrastructure in a way that may affect the casing monitoring
capabilities and testing frequencies specified in the table set forth in
paragraph (c)(4) of this section.
(b) Testing methodologies. You must:
(1) Test safety valves and other equipment at the intervals
specified in the tables set forth in paragraph (c) of this section or
more frequently if operating conditions warrant; and
(2) Perform testing and inspections in accordance with API RP 14C,
Appendix D (incorporated by reference as specified in Sec. 250.198),
and the additional requirements specified in the tables of this section
or as approved in the DWOP for your subsea system.
(c) Testing frequencies. You must:
(1) Comply with the following testing requirements for subsurface
safety devices on dry tree wells:

[[Page 186]]

----------------------------------------------------------------------------------------------------------------
Testing frequency, allowable leakage rates,
Item name and other requirements
----------------------------------------------------------------------------------------------------------------
(i) Surface-controlled SSSVs (including devices installed in shut- Semi-annually, not to exceed 6 calendar
in and injection wells. months between tests. Also test in place
when first installed or reinstalled. If
the device does not operate properly, or
if a liquid leakage rate 400
cubic centimeters per minute or a gas
leakage rate 15 standard cubic
feet per minute is observed, the device
must be removed, repaired, and reinstalled
or replaced. Testing must be according to
API RP 14B (incorporated by reference as
specified in Sec. 250.198) to ensure
proper operation.
(ii) Subsurface-controlled SSSVs................................... Semi-annually, not to exceed 6 calendar
months between tests for valves not
installed in a landing nipple and 12
months for valves installed in a landing
nipple. The valve must be removed,
inspected, and repaired or adjusted, as
necessary, and reinstalled or replaced.
(iii) Tubing plug.................................................. Semi-annually, not to exceed 6 calendar
months between tests. Test by opening the
well to possible flow. If a liquid leakage
rate 400 cubic centimeters per
minute or a gas leakage rate
15 standard cubic feet per minute is
observed, the plug must be removed,
repaired, and reinstalled or replaced. An
additional tubing plug may be installed in
lieu of removal.
(iv) Injection valves.............................................. Semi-annually, not to exceed 6 calendar
months between tests. Test by opening the
well to possible flow. If a liquid leakage
rate 400 cubic centimeters per
minute or a gas leakage rate
15 standard cubic feet per minute is
observed, the valve must be removed,
repaired and reinstalled or replaced.
----------------------------------------------------------------------------------------------------------------

[[Page 187]]

(2) Comply with the following testing requirements for surface
valves:

[[Page 188]]

[[Page 189]]

(3) Comply with the following testing requirements for surface
safety systems and devices:

[[Page 190]]

----------------------------------------------------------------------------------------------------------------
Item name Testing frequency and requirements
----------------------------------------------------------------------------------------------------------------
(i) Pumps for firewater systems.................................... Must be inspected and operated according to
API RP 14G, Section 7.2 (incorporated by
reference as specified in Sec. 250.198).
(ii) Fire- (flame, heat, or smoke) and gas detection systems....... Must be tested for operation and
recalibrated every 3 months, not to exceed
120 days between tests, provided that
testing can be performed in a non-
destructive manner. Open flame or devices
operating at temperatures that could
ignite a methane-air mixture must not be
used. All combustible gas-detection
systems must be calibrated every 3 months.
(iii) ESD systems.................................................. (A) Pneumatic based ESD systems must be
tested for operation at least once each
calendar month, not to exceed 6 weeks
between tests. You must conduct the test
by alternating ESD stations monthly to
close at least one wellhead SSV and verify
a surface-controlled SSSV closure for that
well as indicated by control circuitry
actuation. All stations must be checked
for functionality at least once each
calendar month, not to exceed 6 weeks
between tests. No station may be reused
until all stations have been tested.
(B) Electronic based ESD systems must be
tested for operation at least once every 3
calendar months, not to exceed 120 days
between tests. The test must be conducted
by alternating ESD stations to close at
least one wellhead SSV and verify a
surface-controlled SSSV closure for that
well as indicated by control circuitry
actuation. All stations must be checked
for functionality at least once every 3
calendar months, not to exceed 120 days
between checks. No station may be reused
until all stations have been tested.
(C) Electronic/pneumatic based ESD systems
must be tested for operation at least once
every 3 calendar months, not to exceed 120
days between tests. The test must be
conducted by alternating ESD stations to
close at least one wellhead SSV and verify
a surface-controlled SSSV closure for that
well as indicated by control circuitry
actuation. All stations must be checked
for functionality at least once every 3
calendar months, not to exceed 120 days
between checks. No station may be reused
until all stations have been used.
(iv) TSH devices................................................... Must be tested for operation annually, not
to exceed 12 calendar months between
tests, excluding those addressed in
paragraph (c)(3)(v) of this section and
those that would be destroyed by testing.
Those that could be destroyed by testing
must be visually inspected and the circuit
tested for operations at least once every
12 months.
(v) TSH shutdown controls installed on compressor installations Must be tested every 6 months and repaired
that can be nondestructively tested. or replaced as necessary.
(vi) Burner safety low............................................. Must be tested annually, not to exceed 12
calendar months between tests.
(vii) Flow safety low devices...................................... Must be tested annually, not to exceed 12
calendar months between tests.
(viii) Flame, spark, and detonation arrestors...................... Must be visually inspected annually, not to
exceed 12 calendar months between
inspections.
(ix) Electronic pressure transmitters and level sensors: PSH and Must be tested at least once every 3
PSL; LSH and LSL. months, not to exceed 120 days between
tests.
(x) Pneumatic/electronic switch PSH and PSL; pneumatic/electronic Must be tested at least once each calendar
switch/electric analog with mechanical linkage LSH and LSL month, not to exceed 6 weeks between
controls. tests.
----------------------------------------------------------------------------------------------------------------

[[Page 191]]

(4) Comply with the following testing requirements for subsurface
safety devices and associated systems on subsea tree wells:

[[Page 192]]

----------------------------------------------------------------------------------------------------------------
Testing frequency, allowable leakage rates,
Item name and other requirements
----------------------------------------------------------------------------------------------------------------
(i) Surface-controlled SSSVs (including devices installed in shut- Tested semiannually, not to exceed 6 months
in and injection wells). between tests. If the device does not
operate properly, or if a liquid leakage
rate 400 cubic centimeters per
minute or a gas leakage rate
15 standard cubic feet per minute is
observed, the device must be removed,
repaired, and reinstalled or replaced.
Testing must be according to API RP 14B
(incorporated by reference as specified in
Sec. 250.198) to ensure proper
operation, or as approved in your DWOP.
(ii) USVs.......................................................... Tested at least once every 3 calendar
months, not to exceed 120 days between
tests. If the device does not function
properly, or if a liquid leakage rate 400 cubic centimeters per minute
or a gas leakage rate 15
standard cubic feet per minute is
observed, the valve must be removed,
repaired, and reinstalled or replaced.
(iii) BSDVs........................................................ Tested at least once each calendar month,
not to exceed 6 weeks between tests.
Valves must be tested for both operation
and leakage. You must test according to
API RP 14H for SSVs (incorporated by
reference as specified in Sec. 250.198).
If a BSDV does not operate properly or if
any fluid flow is observed during the
leakage test, the valve must be
immediately repaired or replaced.
(iv) Electronic ESD logic.......................................... Tested at least once each calendar month,
not to exceed 6 weeks between tests.
(v) Electronic ESD function........................................ Tested at least once every 3 calendar
months, not to exceed 120 days between
tests. Shut-in at least one well during
the ESD function test. If multiple wells
are tied back to the same platform, a
different well should be shut-in with each
quarterly test.
----------------------------------------------------------------------------------------------------------------

[[Page 193]]

(d) Subsea wells. (1) Any subsea well that is completed and
disconnected from monitoring capability may not be disconnected for more
than 24 months, unless authorized by BSEE.
(2) Any subsea well that is completed and disconnected from
monitoring capability for more than 6 months must meet the following
testing and other requirements:
(i) Each well must have 3 pressure barriers:
(A) A closed and tested surface-controlled SSSV,
(B) A closed and tested USV, and
(C) One additional closed and tested tree valve.
(ii) For new completed wells, prior to the rig leaving the well, the
pressure barriers must be tested as follows:
(A) The surface-controlled SSSV must be tested for leakage in
accordance with Sec. 250.828(c);
(B) The USV and other pressure barrier must be tested to confirm
zero leakage rate.
(iii) A sealing pressure cap must be installed on the flowline
connection hub until the flowline is installed and connected. The
pressure cap must be designed to accommodate monitoring for pressure
between the production wing valve and cap. The pressure cap must also be
designed so that a remotely operated vehicle can bleed pressure off,
monitor for buildup, and confirm barrier integrity.
(iv) Pressure monitoring at the sealing pressure cap on the flowline
connection hub must be performed in each well at intervals not to exceed
12 months from the time of initial testing of the pressure barrier
(prior to demobilizing the rig from the field).
(v) You must have a drilling vessel capable of intervention into the
disconnected well in the field or readily accessible for use until the
wells are brought on line.

Sec. Sec. 250.881--250.889 [Reserved]

Records and Training

Sec. 250.890 Records.

(a) You must maintain records that show the present status and
history of each safety device. Your records must include dates and
details of installation, removal, inspection, testing, repairing,
adjustments, and reinstallation.
(b) You must maintain these records for at least 2 years. You must
maintain the records at your field office nearest the OCS facility and a
secure onshore location. These records must be available for review by a
representative of BSEE.
(c) You must submit to the appropriate District Manager a contact
list for all OCS facilities at least annually or when contact
information is revised. The contact list must include:
(1) Designated operator name;
(2) Designated primary point of contact for the facility;
(3) Facility phone number(s), if applicable;
(4) Facility fax number, if applicable;
(5) Facility radio frequency, if applicable;
(6) Facility helideck rating and size, if applicable; and
(7) Facility records location if not contained on the facility.

Sec. 250.891 Safety device training.

You must ensure that personnel installing, repairing, testing,
maintaining, and operating surface and subsurface safety devices, and
personnel operating production platforms (including, but not limited to,
separation, dehydration, compression, sweetening, and metering
operations), are trained in accordance with the procedures in subpart O
and subpart S of this part.

Sec. Sec. 250.892-250.899 [Reserved]

Subpart I_Platforms and Structures

General Requirements for Platforms

Sec. 250.900 What general requirements apply to all platforms?

(a) You must design, fabricate, install, use, maintain, inspect, and
assess all platforms and related structures on the Outer Continental
Shelf (OCS) so as to ensure their structural integrity for the safe
conduct of drilling, workover, and production operations. In doing this,
you must consider the specific environmental conditions at the platform
location.

[[Page 194]]

(b) You must also submit an application under Sec. 250.905 of this
subpart and obtain the approval of the Regional Supervisor before
performing any of the activities described in the following table:

------------------------------------------------------------------------
Activity requiring application and Conditions for conducting the
approval activity
------------------------------------------------------------------------
(1) Install a platform. This includes (i) You must adhere to the
placing a newly constructed platform requirements of this subpart,
at a location or moving an existing including the industry
platform to a new site. standards in Sec. 250.901.
(ii) If you are installing a
floating platform, you must
also adhere to U.S. Coast
Guard (USCG) regulations for
the fabrication, installation,
and inspection of floating OCS
facilities.
(2) Major modification to any platform. (i) You must adhere to the
This includes any structural changes requirements of this subpart,
that materially alter the approved including the industry
plan or cause a major deviation from standards in Sec. 250.901.
approved operations and any (ii) Before you make a major
modification that increases loading on modification to a floating
a platform by 10 percent or more. platform, you must obtain
approval from both the BSEE
and the USCG for the
modification.
(3) Major repair of damage to any (i) You must adhere to the
platform. This includes any corrective requirements of this subpart,
operations involving structural including the industry
members affecting the structural standards in Sec. 250.901.
integrity of a portion or all of the (ii) Before you make a major
platform. repair to a floating platform,
you must obtain approval from
both the BSEE and the USCG for
the repair.
(4) Convert an existing platform at the (i) The Regional Supervisor
current location for a new purpose. will determine on a case-by-
case basis the requirements
for an application for
conversion of an existing
platform at the current
location.
(ii) At a minimum, your
application must include: the
converted platform's intended
use; and a demonstration of
the adequacy of the design and
structural condition of the
converted platform.
(iii) If a floating platform,
you must also adhere to USCG
regulations for the
fabrication, installation, and
inspection of floating OCS
facilities.
(5) Convert an existing mobile offshore (i) The Regional Supervisor
drilling unit (MODU) for a new purpose. will determine on a case-by-
case basis the requirements
for an application for
conversion of an existing
MODU.
(ii) At a minimum, your
application must include: the
converted MODU's intended
location and use; a
demonstration of the adequacy
of the design and structural
condition of the converted
MODU; and a demonstration that
the level of safety for the
converted MODU is at least
equal to that of re-used
platforms.
(iii) You must also adhere to
USCG regulations for the
fabrication, installation, and
inspection of floating OCS
facilities.
------------------------------------------------------------------------

(c) Under emergency conditions, you may make repairs to primary
structural elements to restore an existing permitted condition without
submitting an application or receiving prior BSEE approval for up to
120-calendar days following an event. You must notify the Regional
Supervisor of the damage that occurred within 24 hours of its discovery,
and you must provide a written completion report to the Regional
Supervisor of the repairs that were made within 1 week after completing
the repairs. If you make emergency repairs on a floating platform, you
must also notify the USCG.
(d) You must determine if your new platform or major modification to
an existing platform is subject to the Platform Verification Program
(PVP). Section 250.910 of this subpart fully describes the facilities
that are subject to the PVP. If you determine that your platform is
subject to the PVP, you must follow the requirements of Sec. Sec.
250.909 through 250.918 of this subpart.
(e) You must submit notification of the platform installation date
and the final as-built location data to the Regional Supervisor within
45-calendar days of completion of platform installation.
(1) For platforms not subject to the Platform Verification Program
(PVP), BSEE will cancel the approved platform application 1 year after
the approval has been granted if the platform has not been installed. If
BSEE cancels the approval, you must resubmit your platform application
and receive BSEE approval if you still plan to install the platform.
(2) For platforms subject to the PVP, cancellation of an approval
will be on an individual platform basis. For these

[[Page 195]]

platforms, BSEE will identify the date when the installation approval
will be cancelled (if installation has not occurred) during the
application and approval process. If BSEE cancels your installation
approval, you must resubmit your platform application and receive BSEE
approval if you still plan to install the platform.

Sec. 250.901 What industry standards must your platform meet?

(a) In addition to the other requirements of this subpart, your
plans for platform design, analysis, fabrication, installation, use,
maintenance, inspection and assessment must, as appropriate, conform to:
(1) ACI Standard 318-95, Building Code Requirements for Reinforced
Concrete (ACI 318-95) and Commentary (ACI 318R-95) (incorporated by
reference at Sec. 250.198);
(2) ACI 357R-84, Guide for the Design and Construction of Fixed
Offshore Concrete Structures, 1984; reapproved 1997 (incorporated by
reference at Sec. 250.198);
(3) ANSI/AISC 360-05, Specification for Structural Steel Buildings,
(as specified in Sec. 250.198);
(4) American Petroleum Institute (API) Bulletin 2INT-DG, Interim
Guidance for Design of Offshore Structures for Hurricane Conditions, (as
incorporated by reference in Sec. 250.198);
(5) API Bulletin 2INT-EX, Interim Guidance for Assessment of
Existing Offshore Structures for Hurricane Conditions, (as incorporated
by reference in Sec. 250.198);
(6) API Bulletin 2INT-MET, Interim Guidance on Hurricane Conditions
in the Gulf of Mexico, (as incorporated by reference in Sec. 250.198);
(7) API Recommend Practice (RP) 2A-WSD, RP for Planning, Designing,
and Constructing Fixed Offshore Platforms--Working Stress Design (as
incorporated by reference in Sec. 250.198);
(8) API RP 2FPS, Recommended Practice for Planning, Designing, and
Constructing Floating Production Systems, (as incorporated by reference
in Sec. 250.198);
(9) API RP 2I, In-Service Inspection of Mooring Hardware for
Floating Drilling Units (as incorporated by reference in Sec. 250.198);
(10) API RP 2RD, Design of Risers for Floating Production Systems
(FPSs) and Tension-Leg Platforms (TLPs), (as incorporated by reference
in Sec. 250.198);
(11) API RP 2SK, Recommended Practice for Design and Analysis of
Station Keeping Systems for Floating Structures, (as incorporated by
reference in Sec. 250.198);
(12) API RP 2SM, Recommended Practice for Design, Manufacture,
Installation, and Maintenance of Synthetic Fiber Ropes for Offshore
Mooring, (as incorporated by reference in Sec. 250.198);
(13) API RP 2T, Recommended Practice for Planning, Designing and
Constructing Tension Leg Platforms, (as incorporated by reference in
Sec. 250.198);
(14) API RP 14J, Recommended Practice for Design and Hazards
Analysis for Offshore Production Facilities, (as incorporated by
reference in Sec. 250.198);
(15) American Society for Testing and Materials (ASTM) Standard C
33-07, approved December 15, 2007, Standard Specification for Concrete
Aggregates (as incorporated by reference in Sec. 250.198);
(16) ASTM Standard C 94/C 94M-07, approved January 1, 2007, Standard
Specification for Ready-Mixed Concrete (as incorporated by reference in
Sec. 250.198);
(17) ASTM Standard C 150-07, approved May 1, 2007, Standard
Specification for Portland Cement (as incorporated by reference in Sec.
250.198);
(18) ASTM Standard C 330-05, approved December 15, 2005, Standard
Specification for Lightweight Aggregates for Structural Concrete (as
incorporated by reference in Sec. 250.198);
(19) ASTM Standard C 595-08, approved January 1, 2008, Standard
Specification for Blended Hydraulic Cements (as incorporated by
reference in Sec. 250.198);
(20) AWS D1.1, Structural Welding Code--Steel, including Commentary,
(as incorporated by reference in Sec. 250.198);
(21) AWS D1.4, Structural Welding Code--Reinforcing Steel, (as
incorporated by reference in Sec. 250.198);
(22) AWS D3.6M, Specification for Underwater Welding, (as
incorporated by reference in Sec. 250.198);

[[Page 196]]

(23) NACE Standard MR0175, Sulfide Stress Cracking Resistant
Metallic Materials for Oilfield Equipment, (as incorporated by reference
in Sec. 250.198);
(24) NACE Standard RP0176-2003, Item No. 21018, Standard Recommended
Practice, Corrosion Control of Steel Fixed Offshore Structures
Associated with Petroleum Production (as incorporated by reference in
Sec. 250.198).
(b) You must follow the requirements contained in the documents
listed under paragraph (a) of this section insofar as they do not
conflict with other provisions of 30 CFR part 250. You may use
applicable provisions of these documents, as approved by the Regional
Supervisor, for the design, fabrication, and installation of platforms
such as spars, since standards specifically written for such structures
do not exist. You may also use alternative codes, rules, or standards,
as approved by the Regional Supervisor, under the conditions enumerated
in Sec. 250.141.
(c) For information on the standards mentioned in this section, and
where they may be obtained, see Sec. 250.198 of this part.
(d) The following chart summarizes the applicability of the industry
standards listed in this section for fixed and floating platforms:

------------------------------------------------------------------------
Applicable to . .
Industry standard .
------------------------------------------------------------------------
(1) ACI Standard 318-95, Building Code Requirements Fixed and
for Reinforced Concrete (ACI 318-95) and Commentary floating
(ACI 318R-95), platform, as
appropriate.
(2) ANSI/AISC 360-05, Specification for Structural
Steel Buildings;
(3) API Bulletin 2INT-DG, Interim Guidance for Design
of Offshore Structures for Hurricane Conditions;
(4) API Bulletin 2INT-EX, Interim Guidance for
Assessment of Existing Offshore Structures for
Hurricane Conditions;
(5) API Bulletin 2INT-MET, Interim Guidance on
Hurricane Conditions in the Gulf of Mexico;
(6) API RP 2A-WSD, RP for Planning, Designing, and
Constructing Fixed Offshore Platforms--Working
Stress Design;
(7) ASTM Standard C 33-07, approved December 15,
2007, Standard Specification for Concrete
Aggregates;
(8) ASTM Standard C 94/C 94M-07, approved January 1,
2007, Standard Specification for Ready-Mixed
Concrete;
(9) ASTM Standard C 150-07, approved May 1, 2007,
Standard Specification for Portland Cement;
(10) ASTM Standard C 330-05, approved December 15,
2005, Standard Specification for Lightweight
Aggregates for Structural Concrete;
(11) ASTM Standard C 595-08, approved January 1,
2008, Standard Specification for Blended Hydraulic
Cements;
(12) AWS D1.1, Structural Welding Code--Steel;
(13) AWS D1.4, Structural Welding Code--Reinforcing
Steel;
(14) AWS D3.6M, Specification for Underwater Welding;
(15) NACE Standard RP 0176-2003, Standard Recommended
Practice (RP), Corrosion Control of Steel Fixed
Offshore Platforms Associated with Petroleum
Production;
(16) ACI 357R-84, Guide for the Design and Fixed platforms.
Construction of Fixed Offshore Concrete Structures,
1984; reapproved 1997,
(17) API RP 14J, RP for Design and Hazards Analysis Floating
for Offshore Production Facilities; platforms.
(18) API RP 2FPS, RP for Planning, Designing, and
Constructing, Floating Production Systems;
(19) API RP 2RD, Design of Risers for Floating
Production Systems (FPSs) and Tension-Leg Platforms
(TLPs);
(20) API RP 2SK, RP for Design and Analysis of
Station Keeping Systems for Floating Structures;
(21) API RP 2T, RP for Planning, Designing, and
Constructing Tension Leg Platforms;
(22) API RP 2SM, RP for Design, Manufacture,
Installation, and Maintenance of Synthetic Fiber
Ropes for Offshore Mooring;
(23) API RP 2I, In-Service Inspection of Mooring .................
Hardware for Floating Drilling Units
------------------------------------------------------------------------

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36150, June 6, 2016]

Sec. 250.902 What are the requirements for platform removal
and location clearance?

You must remove all structures according to Sec. Sec. 250.1725
through 250.1730 of Subpart Q--Decommissioning Activities of this part.

[[Page 197]]

Sec. 250.903 What records must I keep?

(a) You must compile, retain, and make available to BSEE
representatives for the functional life of all platforms:
(1) The as-built drawings;
(2) The design assumptions and analyses;
(3) A summary of the fabrication and installation nondestructive
examination records;
(4) The inspection results from the inspections required by Sec.
250.919 of this subpart; and
(5) Records of repairs not covered in the inspection report
submitted under Sec. 250.919(b).
(b) You must record and retain the original material test results of
all primary structural materials during all stages of construction.
Primary material is material that, should it fail, would lead to a
significant reduction in platform safety, structural reliability, or
operating capabilities. Items such as steel brackets, deck stiffeners
and secondary braces or beams would not generally be considered primary
structural members (or materials).
(c) You must provide BSEE with the location of these records in the
certification statement of your application for platform approval as
required in Sec. 250.905(j).

Platform Approval Program

Sec. 250.904 What is the Platform Approval Program?

(a) The Platform Approval Program is the BSEE basic approval process
for platforms on the OCS. The requirements of the Platform Approval
Program are described in Sec. Sec. 250.904 through 250.908 of this
subpart. Completing these requirements will satisfy BSEE criteria for
approval of fixed platforms of a proven design that will be placed in
the shallow water areas (<=400 ft.) of the Gulf of Mexico OCS.
(b) The requirements of the Platform Approval Program must be met by
all platforms on the OCS. Additionally, if you want approval for a
floating platform; a platform of unique design; or a platform being
installed in deepwater ( 400 ft.) or a frontier area, you
must also meet the requirements of the Platform Verification Program.
The requirements of the Platform Verification Program are described in
Sec. Sec. 250.909 through 250.918 of this subpart.

Sec. 250.905 How do I get approval for the installation, modification,
or repair of my platform?

The Platform Approval Program requires that you submit the
information, documents, and fee listed in the following table for your
proposed project. In lieu of submitting the paper copies specified in
the table, you may submit your application electronically in accordance
with 30 CFR 250.186(a)(3).

------------------------------------------------------------------------
Required submittal Required contents Other requirements
------------------------------------------------------------------------
(a) Application cover letter Proposed structure You must submit
designation, lease three copies. If,
number, area, name, your facility is
and block number, subject to the
and the type of Platform
facility your Verification
facility (e.g., Program (PVP), you
drilling, must submit four
production, copies.
quarters). The
structure
designation must be
unique for the
field (some fields
are made up of
several blocks);
i.e. once a
platform ``A'' has
been used in the
field there should
never be another
platform ``A'' even
if the old platform
``A'' has been
removed. Single
well free standing
caissons should be
given the same
designation as the
well. All other
structures are to
be designated by
letter designations.

[[Page 198]]

(b) Location plat........... Latitude and Your plat must be
longitude drawn to a scale of
coordinates, 1 inch equals 2,000
Universal Mercator feet and include
grid-system the coordinates of
coordinates, state the lease block
plane coordinates boundary lines. You
in the Lambert or must submit three
Transverse Mercator copies.
Projection System,
and distances in
feet from the
nearest block
lines. These
coordinates must be
based on the NAD
(North American
Datum) 27 datum
plane coordinate
system.
(c) Front, Side, and Plan Platform dimensions Your drawing sizes
View drawings. and orientation, must not exceed
elevations relative 11 x
to M.L.L.W. (Mean 17. You
Lower Low Water), must submit three
and pile sizes and copies (four copies
penetration. for PVP
applications).
(d) Complete set of The approved for Your drawing sizes
structural drawings. construction must not exceed
fabrication 11 x
drawings should be 17. You
submitted must submit one
including; e.g., copy.
cathodic protection
systems; jacket
design; pile
foundations;
drilling,
production, and
pipeline risers and
riser tensioning
systems; turrets
and turret-and-hull
interfaces; mooring
and tethering
systems;
foundations and
anchoring systems.
(e) Summary of environmental A summary of the You must submit one
data. environmental data copy.
described in the
applicable
standards
referenced under
Sec. 250.901(a)
of this subpart and
in Sec. 250.198
of Subpart A, where
the data is used in
the design or
analysis of the
platform. Examples
of relevant data
include information
on waves, wind,
current, tides,
temperature, snow
and ice effects,
marine growth, and
water depth.
(f) Summary of the Loading information You must submit one
engineering design data. (e.g., live, dead, copy.
environmental),
structural
information (e.g.,
design-life;
material types;
cathodic protection
systems; design
criteria; fatigue
life; jacket
design; deck
design; production
component design;
pile foundations;
drilling,
production, and
pipeline risers and
riser tensioning
systems; turrets
and turret-and-hull
interfaces;
foundations,
foundation pilings
and templates, and
anchoring systems;
mooring or
tethering systems;
fabrication and
installation
guidelines), and
foundation
information (e.g.,
soil stability,
design criteria).
(g) Project-specific studies All studies You must submit one
used in the platform design pertinent to copy of each study.
or installation. platform design or
installation, e.g.,
oceanographic and/
or soil reports
including the
overall site
investigative
report required in
Sec. 250.906.
(h) Description of the loads Loads imposed by You must submit one
imposed on the facility. jacket; decks; copy.
production
components;
drilling,
production, and
pipeline risers,
and riser
tensioning systems;
turrets and turret-
and-hull
interfaces;
foundations,
foundation pilings
and templates, and
anchoring systems;
and mooring or
tethering systems.
(i) Summary of safety A summary of You must submit one
factors utilized. pertinent derived copy.
factors of safety
against failure for
major structural
members, e.g.,
unity check ratios
exceeding 0.85 for
steel-jacket
platform members,
indicated on
``line'' sketches
of jacket sections.
(j) A copy of the in-service This plan is You must submit one
inspection plan. described in Sec. copy.
250.919.

[[Page 199]]

(k) Certification statement. The following An authorized
statement: ``The company
design of this representative must
structure has been sign the statement.
certified by a You must submit one
recognized copy.
classification
society, or a
registered civil or
structural engineer
or equivalent, or a
naval architect or
marine engineer or
equivalent,
specializing in the
design of offshore
structures. The
certified design
and as-built plans
and specifications
will be on file at
(give location)''.
(l) Payment of the service
fee listed in Sec.
250.125.
------------------------------------------------------------------------

Sec. 250.906 What must I do to obtain approval for the proposed site
of my platform?

(a) Shallow hazards surveys. You must perform a high-resolution or
acoustic-profiling survey to obtain information on the conditions
existing at and near the surface of the seafloor. You must collect
information through this survey sufficient to determine the presence of
the following features and their likely effects on your proposed
platform:
(1) Shallow faults;
(2) Gas seeps or shallow gas;
(3) Slump blocks or slump sediments;
(4) Shallow water flows;
(5) Hydrates; or
(6) Ice scour of seafloor sediments.
(b) Geologic surveys. You must perform a geological survey relevant
to the design and siting of your platform. Your geological survey must
assess:
(1) Seismic activity at your proposed site;
(2) Fault zones, the extent and geometry of faulting, and
attenuation effects of geologic conditions near your site; and
(3) For platforms located in producing areas, the possibility and
effects of seafloor subsidence.
(c) Subsurface surveys. Depending upon the design and location of
your proposed platform and the results of the shallow hazard and
geologic surveys, the Regional Supervisor may require you to perform a
subsurface survey. This survey will include a testing program for
investigating the stratigraphic and engineering properties of the soil
that may affect the foundations or anchoring systems for your facility.
The testing program must include adequate in situ testing, boring, and
sampling to examine all important soil and rock strata to determine its
strength classification, deformation properties, and dynamic
characteristics. If required to perform a subsurface survey, you must
prepare and submit to the Regional Supervisor a summary report to
briefly describe the results of your soil testing program, the various
field and laboratory test methods employed, and the applicability of
these methods as they pertain to the quality of the samples, the type of
soil, and the anticipated design application. You must explain how the
engineering properties of each soil stratum affect the design of your
platform. In your explanation you must describe the uncertainties
inherent in your overall testing program, and the reliability and
applicability of each test method.
(d) Overall site investigation report. You must prepare and submit
to the Regional Supervisor an overall site investigation report for your
platform that integrates the findings of your shallow hazards surveys
and geologic surveys, and, if required, your subsurface surveys. Your
overall site investigation report must include analyses of the potential
for:
(1) Scouring of the seafloor;
(2) Hydraulic instability;
(3) The occurrence of sand waves;
(4) Instability of slopes at the platform location;
(5) Liquefaction, or possible reduction of soil strength due to
increased pore pressures;
(6) Degradation of subsea permafrost layers;
(7) Cyclic loading;
(8) Lateral loading;
(9) Dynamic loading;
(10) Settlements and displacements;

[[Page 200]]

(11) Plastic deformation and formation collapse mechanisms; and
(12) Soil reactions on the platform foundations or anchoring
systems.

Sec. 250.907 Where must I locate foundation boreholes?

(a) For fixed or bottom-founded platforms and tension leg platforms,
your maximum distance from any foundation pile to a soil boring must not
exceed 500 feet.
(b) For deepwater floating platforms which utilize catenary or taut-
leg moorings, you must take borings at the most heavily loaded anchor
location, at the anchor points approximately 120 and 240 degrees around
the anchor pattern from that boring, and, as necessary, other points
throughout the anchor pattern to establish the soil profile suitable for
foundation design purposes.

Sec. 250.908 What are the minimum structural fatigue design requirements?

(a) API RP 2A-WSD, Recommended Practice for Planning, Designing and
Constructing Fixed Offshore Platforms (as incorporated by reference in
Sec. 250.198), requires that the design fatigue life of each joint and
member be twice the intended service life of the structure. When
designing your platform, the following table provides minimum fatigue
life safety factors for critical structural members and joints.

------------------------------------------------------------------------
If . . . Then . . .
------------------------------------------------------------------------
(1) There is sufficient structural The results of the fatigue
redundancy to prevent catastrophic analysis must indicate a
failure of the platform or structure minimum calculated life of
under consideration, twice the design life of
the platform.
(2) There is not sufficient structural The results of a fatigue
redundancy to prevent catastrophic analysis must indicate a
failure of the platform or structure, minimum calculated life or
three times the design life
of the platform.
(3) The desirable degree of redundancy is The results of a fatigue
significantly reduced as a result of analysis must indicate a
fatigue damage, minimum calculated life of
three times the design life
of the platform.
------------------------------------------------------------------------

(b) The documents incorporated by reference in Sec. 250.901 may
require larger safety factors than indicated in paragraph (a) of this
section for some key components. When the documents incorporated by
reference require a larger safety factor than the chart in paragraph (a)
of this section, the requirements of the incorporated document will
prevail.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36150, June 6, 2016]

Platform Verification Program

Sec. 250.909 What is the Platform Verification Program?

The Platform Verification Program is the BSEE approval process for
ensuring that floating platforms; platforms of a new or unique design;
platforms in seismic areas; or platforms located in deepwater or
frontier areas meet stringent requirements for design and construction.
The program is applied during construction of new platforms and major
modifications of, or repairs to, existing platforms. These requirements
are in addition to the requirements of the Platform Approval Program
described in Sec. Sec. 250.904 through 250.908 of this subpart.

Sec. 250.910 Which of my facilities are subject to
the Platform Verification Program?

(a) All new fixed or bottom-founded platforms that meet any of the
following five conditions are subject to the Platform Verification
Program:
(1) Platforms installed in water depths exceeding 400 feet (122
meters);
(2) Platforms having natural periods in excess of 3 seconds;
(3) Platforms installed in areas of unstable bottom conditions;
(4) Platforms having configurations and designs which have not
previously been used or proven for use in the area; or
(5) Platforms installed in seismically active areas.
(b) All new floating platforms are subject to the Platform
Verification Program to the extent indicated in the following table:

[[Page 201]]

------------------------------------------------------------------------
If . . . Then . . .
------------------------------------------------------------------------
(1) Your new floating platform is a The entire platform is
buoyant offshore facility that does not subject to the Platform
have a ship-shaped hull, Verification Program
including the following
associated structures:
(i) Drilling, production,
and pipeline risers, and
riser tensioning systems
(each platform must be
designed to accommodate all
the loads imposed by all
risers and riser does not
have tensioning systems);
(ii) Turrets and turret-and-
hull interfaces;
(iii) Foundations,
foundation pilings and
templates, and anchoring
systems; and
(iv) Mooring or tethering
systems.
(2) Your new floating platform is a Only the following
buoyant offshore facility with a ship- structures that may be
shaped hull, associated with a floating
platform are subject to the
Platform Verification
Program:
(i) Drilling, production,
and pipeline risers, and
riser tensioning systems
(each platform must be
designed to accommodate all
the loads imposed by all
risers and riser tensioning
systems);
(ii) Turrets and turret-and-
hull interfaces;
(iii) Foundations,
foundation pilings and
templates, and anchoring
systems; and
(iv) Mooring or tethering
systems.
------------------------------------------------------------------------

(c) If a platform is originally subject to the Platform Verification
Program, then the conversion of that platform at that same site for a
new purpose, or making a major modification of, or major repair to, that
platform, is also subject to the Platform Verification Program. A major
modification includes any modification that increases loading on a
platform by 10 percent or more. A major repair is a corrective operation
involving structural members affecting the structural integrity of a
portion or all of the platform. Before you make a major modification or
repair to a floating platform, you must obtain approval from both the
BSEE and the USCG.
(d) The applicability of Platform Verification Program requirements
to other types of facilities will be determined by BSEE on a case-by-
case basis.

Sec. 250.911 If my platform is subject to the Platform Verification Program,
what must I do?

If your platform, conversion, or major modification or repair meets
the criteria in Sec. 250.910, you must:
(a) Design, fabricate, install, use, maintain and inspect your
platform, conversion, or major modification or repair to your platform
according to the requirements of this subpart, and the applicable
documents listed in Sec. 250.901(a) of this subpart;
(b) Comply with all the requirements of the Platform Approval
Program found in Sec. Sec. 250.904 through 250.908 of this subpart.
(c) Submit for the Regional Supervisor's approval three copies each
of the design verification, fabrication verification, and installation
verification plans required by Sec. 250.912;
(d) Submit a complete schedule of all phases of design, fabrication,
and installation for the Regional Supervisor's approval. You must
include a project management timeline, Gantt Chart, that depicts when
interim and final reports required by Sec. Sec. 250.916, 250.917, and
250.918 will be submitted to the Regional Supervisor for each phase. On
the timeline, you must break-out the specific scopes of work that
inherently stand alone (e.g., deck, mooring systems, tendon systems,
riser systems, turret systems).
(e) Include your nomination of a Certified Verification Agent (CVA)
as a part of each verification plan required by Sec. 250.912;
(f) Follow the additional requirements in Sec. Sec. 250.913 through
250.918;
(g) Obtain approval for modifications to approved plans and for
major deviations from approved installation procedures from the Regional
Supervisor; and
(h) Comply with applicable USCG regulations for floating OCS
facilities.

[[Page 202]]

Sec. 250.912 What plans must I submit under
the Platform Verification Program?

If your platform, associated structure, or major modification meets
the criteria in Sec. 250.910, you must submit the following plans to
the Regional Supervisor for approval:
(a) Design verification plan. You may submit your design
verification plan to BSEE with or subsequent to the submittal of your
Development and Production Plan (DPP) or Development Operations
Coordination Document (DOCD) to BOEM. Your design verification must be
conducted by, or be under the direct supervision of, a registered
professional civil or structural engineer or equivalent, or a naval
architect or marine engineer or equivalent, with previous experience in
directing the design of similar facilities, systems, structures, or
equipment. For floating platforms, you must ensure that the requirements
of the USCG for structural integrity and stability, e.g., verification
of center of gravity, etc., have been met. Your design verification plan
must include the following:
(1) All design documentation specified in Sec. 250.905 of this
subpart;
(2) Abstracts of the computer programs used in the design process;
and
(3) A summary of the major design considerations and the approach to
be used to verify the validity of these design considerations.
(b) Fabrication verification plan. The Regional Supervisor must
approve your fabrication verification plan before you may initiate any
related operations. Your fabrication verification plan must include the
following:
(1) Fabrication drawings and material specifications for artificial
island structures and major members of concrete-gravity and steel-
gravity structures;
(2) For jacket and floating structures, all the primary load-bearing
members included in the space-frame analysis; and
(3) A summary description of the following:
(i) Structural tolerances;
(ii) Welding procedures;
(iii) Material (concrete, gravel, or silt) placement methods;
(iv) Fabrication standards;
(v) Material quality-control procedures;
(vi) Methods and extent of nondestructive examinations for welds and
materials; and
(vii) Quality assurance procedures.
(c) Installation verification plan. The Regional Supervisor must
approve your installation verification plan before you may initiate any
related operations. Your installation verification plan must include:
(1) A summary description of the planned marine operations;
(2) Contingencies considered;
(3) Alternative courses of action; and
(4) An identification of the areas to be inspected. You must specify
the acceptance and rejection criteria to be used for any inspections
conducted during installation, and for the post-installation
verification inspection.
(d) You must combine fabrication verification and installation
verification plans for manmade islands or platforms fabricated and
installed in place.

Sec. 250.913 When must I resubmit Platform Verification Program plans?

(a) You must resubmit any design verification, fabrication
verification, or installation verification plan to the Regional
Supervisor for approval if:
(1) The CVA changes;
(2) The CVA's or assigned personnel's qualifications change; or
(3) The level of work to be performed changes.
(b) If only part of a verification plan is affected by one of the
changes described in paragraph (a) of this section, you can resubmit
only the affected part. You do not have to resubmit the summary of
technical details unless you make changes in the technical details.

Sec. 250.914 How do I nominate a CVA?

(a) As part of your design verification, fabrication verification,
or installation verification plan, you must nominate a CVA for the
Regional Supervisor's approval. You must specify whether the nomination
is for the design, fabrication, or installation phase of verification,
or for any combination of these phases.

[[Page 203]]

(b) For each CVA, you must submit a list of documents to be
forwarded to the CVA, and a qualification statement that includes the
following:
(1) Previous experience in third-party verification or experience in
the design, fabrication, installation, or major modification of offshore
oil and gas platforms. This should include fixed platforms, floating
platforms, manmade islands, other similar marine structures, and related
systems and equipment;
(2) Technical capabilities of the individual or the primary staff
for the specific project;
(3) Size and type of organization or corporation;
(4) In-house availability of, or access to, appropriate technology.
This should include computer programs, hardware, and testing materials
and equipment;
(5) Ability to perform the CVA functions for the specific project
considering current commitments;
(6) Previous experience with BSEE requirements and procedures;
(7) The level of work to be performed by the CVA.

Sec. 250.915 What are the CVA's primary responsibilities?

(a) The CVA must conduct specified reviews according to Sec. Sec.
250.916, 250.917, and 250.918 of this subpart.
(b) Individuals or organizations acting as CVAs must not function in
any capacity that would create a conflict of interest, or the appearance
of a conflict of interest.
(c) The CVA must consider the applicable provisions of the documents
listed in Sec. 250.901(a); the alternative codes, rules, and standards
approved under Sec. 250.901(b); and the requirements of this subpart.
(d) The CVA is the primary contact with the Regional Supervisor and
is directly responsible for providing immediate reports of all incidents
that affect the design, fabrication and installation of the platform.

Sec. 250.916 What are the CVA's primary duties during the design phase?

(a) The CVA must use good engineering judgment and practices in
conducting an independent assessment of the design of the platform,
major modification, or repair. The CVA must ensure that the platform,
major modification, or repair is designed to withstand the environmental
and functional load conditions appropriate for the intended service life
at the proposed location.
(b) Primary duties of the CVA during the design phase include the
following:

(c) The CVA must submit interim reports and a final report to the
Regional Supervisor, and to you, during the design phase in accordance
with the approved schedule required by Sec. 250.911(d). In each interim
and final report the CVA must:
(1) Provide a summary of the material reviewed and the CVA's
findings;

[[Page 204]]

(2) In the final CVA report, make a recommendation that the Regional
Supervisor either accept, request modifications, or reject the proposed
design unless such a recommendation has been previously made in an
interim report;
(3) Describe the particulars of how, by whom, and when the
independent review was conducted; and
(4) Provide any additional comments the CVA deems necessary.

Sec. 250.917 What are the CVA's primary duties during the fabrication phase?

(a) The CVA must use good engineering judgment and practices in
conducting an independent assessment of the fabrication activities. The
CVA must monitor the fabrication of the platform or major modification
to ensure that it has been built according to the approved design and
the fabrication plan. If the CVA finds that fabrication procedures are
changed or design specifications are modified, the CVA must inform you.
If you accept the modifications, then the CVA must so inform the
Regional Supervisor.
(b) Primary duties of the CVA during the fabrication phase include
the following:

----------------------------------------------------------------------------------------------------------------
Type of facility . . . The CVA must . . .
----------------------------------------------------------------------------------------------------------------
(1) For all fixed platforms and non-ship-shaped Make periodic onsite inspections while fabrication is in
floating facilities, progress and must verify the following fabrication items,
as appropriate:
(i) Quality control by lessee and builder;
(ii) Fabrication site facilities;
(iii) Material quality and identification methods;
(iv) Fabrication procedures specified in the approved
plan, and adherence to such procedures;
(v) Welder and welding procedure qualification and
identification;
(vi) Structural tolerances specified and adherence to
those tolerances;
(vii) The nondestructive examination requirements, and
evaluation results of the specified examinations;
(viii) Destructive testing requirements and results;
(ix) Repair procedures;
(x) Installation of corrosion-protection systems and
splash-zone protection;
(xi) Erection procedures to ensure that overstressing of
structural members does not occur;
(xii) Alignment procedures;
(xiii) Dimensional check of the overall structure,
including any turrets, turret-and-hull interfaces, any
mooring line and chain and riser tensioning line
segments; and
(xiv) Status of quality-control records at various stages
of fabrication.
(2) For all floating facilities, Ensure that the requirements of the U.S. Coast Guard
floating for structural integrity and stability, e.g.,
verification of center of gravity, etc., have been met.
The CVA must also consider:
(i) Drilling, production, and pipeline risers, and riser
tensioning systems (at least for the initial fabrication
of these elements);
(ii) Turrets and turret-and-hull interfaces;
(iii) Foundation pilings and templates, and anchoring
systems; and
(iv) Mooring or tethering systems.
----------------------------------------------------------------------------------------------------------------

(c) The CVA must submit interim reports and a final report to the
Regional Supervisor, and to you, during the fabrication phase in
accordance with the approved schedule required by Sec. 250.911(d). In
each interim and final report the CVA must:
(1) Give details of how, by whom, and when the independent
monitoring activities were conducted;
(2) Describe the CVA's activities during the verification process;
(3) Summarize the CVA's findings;
(4) Confirm or deny compliance with the design specifications and
the approved fabrication plan;
(5) In the final CVA report, make a recommendation to accept or
reject the fabrication unless such a recommendation has been previously
made in an interim report; and
(6) Provide any additional comments that the CVA deems necessary.

[[Page 205]]

Sec. 250.918 What are the CVA's primary duties during the installation phase?

(a) The CVA must use good engineering judgment and practice in
conducting an independent assessment of the installation activities.
(b) Primary duties of the CVA during the installation phase include
the following:

----------------------------------------------------------------------------------------------------------------
The CVA must . . . Operation or equipment to be inspected . . .
----------------------------------------------------------------------------------------------------------------
(1) Verify, as appropriate, (i) Loadout and initial flotation operations;
(ii) Towing operations to the specified location, and
review the towing records;
(iii) Launching and uprighting operations;
(iv) Submergence operations;
(v) Pile or anchor installations;
(vi) Installation of mooring and tethering systems;
(vii) Final deck and component installations; and
(viii) Installation at the approved location according to
the approved design and the installation plan.
(2) Witness (for a fixed or floating platform), (i) The loadout of the jacket, decks, piles, or structures
from each fabrication site;
(ii) The actual installation of the platform or major
modification and the related installation activities.
(3) Witness (for a floating platform), (i) The loadout of the platform;
(ii) The installation of drilling, production, and
pipeline risers, and riser tensioning systems (at least
for the initial installation of these elements);
(iii) The installation of turrets and turret-and-hull
interfaces;
(iv) The installation of foundation pilings and templates,
and anchoring systems; and
(v) The installation of the mooring and tethering systems.
(4) Conduct an onsite survey, Survey the platform after transportation to the approved
location.
(5) Spot-check as necessary to determine compliance (i) Equipment;
with the applicable documents listed in Sec. (ii) Procedures; and
250.901(a); the alternative codes, rules and (iii) Recordkeeping.
standards approved under Sec. 250.901(b); the
requirements listed in Sec. 250.903 and Sec.
Sec. 250.906 through 250.908 of this subpart and
the approved plans,
----------------------------------------------------------------------------------------------------------------

(c) The CVA must submit interim reports and a final report to the
Regional Supervisor, and to you, during the installation phase in
accordance with the approved schedule required by Sec. 250.911(d). In
each interim and final report the CVA must:
(1) Give details of how, by whom, and when the independent
monitoring activities were conducted;
(2) Describe the CVA's activities during the verification process;
(3) Summarize the CVA's findings;
(4) Confirm or deny compliance with the approved installation plan;
(5) In the final report, make a recommendation to accept or reject
the installation unless such a recommendation has been previously made
in an interim report; and
(6) Provide any additional comments that the CVA deems necessary.

Inspection, Maintenance, and Assessment of Platforms

Sec. 250.919 What in-service inspection requirements must I meet?

(a) You must submit a comprehensive in-service inspection report
annually by November 1 to the Regional Supervisor that must include:
(1) A list of fixed and floating platforms you inspected in the
preceding 12 months;
(2) The extent and area of inspection for both the above-water and
underwater portions of the platform and the pertinent components of the
mooring system for floating platforms;
(3) The type of inspection employed (e.g., visual, magnetic
particle, ultrasonic testing);
(4) The overall structural condition of each platform, including a
corrosion protection evaluation; and
(5) A summary of the inspection results indicating what repairs, if
any, were needed.

[[Page 206]]

(b) If any of your structures have been exposed to a natural
occurrence (e.g., hurricane, earthquake, or tropical storm), the
Regional Supervisor may require you to submit an initial report of all
structural damage, followed by subsequent updates, which include the
following:
(1) A list of affected structures;
(2) A timetable for conducting the inspections described in section
14.4.3 of API RP 2A-WSD (as incorporated by reference in Sec. 250.198);
and
(3) An inspection plan for each structure that describes the work
you will perform to determine the condition of the structure.
(c) The Regional Supervisor may also require you to submit the
results of the inspections referred to in paragraph (b)(2) of this
section, including a description of any detected damage that may
adversely affect structural integrity, an assessment of the structure's
ability to withstand any anticipated environmental conditions, and any
remediation plans. Under Sec. Sec. 250.900(b)(3) and 250.905, you must
obtain approval from BSEE before you make major repairs of any damage
unless you meet the requirements of Sec. 250.900(c).

Sec. 250.920 What are the BSEE requirements for assessment
of fixed platforms?

(a) You must document all wells, equipment, and pipelines supported
by the platform if you intend to use either the A-2 or A-3 assessment
category. Assessment categories are defined in API RP 2A-WSD, Section
17.3 (as incorporated by reference in Sec. 250.198). If BSEE objects to
the assessment category you used for your assessment, you may need to
redesign and/or modify the platform to adequately demonstrate that the
platform is able to withstand the environmental loadings for the
appropriate assessment category.
(b) You must perform an analysis check when your platform will have
additional personnel, additional topside facilities, increased
environmental or operational loading, inadequate deck height, or
suffered significant damage (e.g., experienced damage to primary
structural members or conductor guide trays or global structural
integrity is adversely affected); or the exposure category changes to a
more restrictive level (see Sections 17.2.1 through 17.2.5 of API RP 2A-
WSD, incorporated by reference in Sec. 250.198, for a description of
assessment initiators).
(c) You must initiate mitigation actions for platforms that do not
pass the assessment process of API RP 2A-WSD. You must submit
applications for your mitigation actions (e.g., repair, modification,
decommissioning) to the Regional Supervisor for approval before you
conduct the work.
(d) The BSEE may require you to conduct a platform design basis
check when the reduced environmental loading criteria contained in API
RP 2A-WSD Section 17.6 are not applicable.
(e) By November 1, 2009, you must submit a complete list of all the
platforms you operate, together with all the appropriate data to support
the assessment category you assign to each platform and the platform
assessment initiators (as defined in API RP 2A-WSD) to the Regional
Supervisor. You must submit subsequent complete lists and the
appropriate data to support the consequence-of-failure category every 5
years thereafter, or as directed by the Regional Supervisor.
(f) The use of Section 17, Assessment of Existing Platforms, of API
RP 2A-WSD is limited to existing fixed structures that are serving their
original approved purpose. You must obtain approval from the Regional
Supervisor for any change in purpose of the platform, following the
provisions of API RP 2A-WSD, Section 15, Re-use.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36150, June 6, 2016]

Sec. 250.921 How do I analyze my platform for cumulative fatigue?

(a) If you are required to analyze cumulative fatigue on your
platform because of the results of an inspection or platform assessment,
you must ensure that the safety factors for critical elements listed in
Sec. 250.908 are met or exceeded.
(b) If the calculated life of a joint or member does not meet the
criteria of Sec. 250.908, you must either mitigate the load, strengthen
the joint or member, or develop an increased inspection process.

[[Page 207]]

Subpart J_Pipelines and Pipeline Rights-of-Way

Sec. 250.1000 General requirements.

(a) Pipelines and associated valves, flanges, and fittings shall be
designed, installed, operated, maintained, and abandoned to provide safe
and pollution-free transportation of fluids in a manner which does not
unduly interfere with other uses in the Outer Continental Shelf (OCS).
(b) An application must be accompanied by payment of the service fee
listed in Sec. 250.125 and submitted to the Regional Supervisor and
approval obtained before:
(1) Installation, modification, or abandonment of a lease term
pipeline;
(2) Installation or modification of a right-of-way (other than lease
term) pipeline; or
(3) Modification or relinquishment of a pipeline right-of way.
(c)(1) Department of the Interior (DOI) pipelines, as defined in
Sec. 250.1001, must meet the requirements in Sec. Sec. 250.1000
through 250.1008.
(2) A pipeline right-of-way grant holder must identify in writing to
the Regional Supervisor the operator of any pipeline located on its
right-of-way, if the operator is different from the right-of-way grant
holder.
(3) A producing operator must identify for its own records, on all
existing pipelines located on its lease or right-of-way, the specific
points at which operating responsibility transfers to a transporting
operator.
(i) Each producing operator must, if practical, durably mark all of
its above-water transfer points as of the date a pipeline begins
service.
(ii) If it is not practical to durably mark a transfer point, and
the transfer point is located above water, then the operator must
identify the transfer point on a schematic located on the facility.
(iii) If a transfer point is located below water, then the operator
must identify the transfer point on a schematic and provide the
schematic to BSEE upon request.
(iv) If adjoining producing and transporting operators cannot agree
on a transfer point, the BSEE Regional Supervisor and the appropriate
Department of Transportation (DOT) pipeline official may jointly
determine the transfer point.
(4) The transfer point serves as a regulatory boundary. An operator
may request that the BSEE Regional Supervisor grant an exception to this
requirement for an individual facility or area. The Regional Supervisor,
in consultation with the appropriate DOT pipeline official and affected
parties, may grant the request.
(5) Pipeline segments designed, constructed, maintained, and
operated under DOT regulations but transferring to DOI regulation as of
October 16, 1998, may continue to operate under DOT design and
construction requirements until significant modifications or repairs are
made to those segments. After October 16, 1998, BSEE operational and
maintenance requirements will apply to those segments.
(6) Any producer operating a pipeline that crosses into State waters
without first connecting to a transporting operator's facility on the
OCS must comply with this subpart. Compliance must extend from the point
where hydrocarbons are first produced, through and including the last
valve and associated safety equipment (e.g., pressure safety sensors) on
the last production facility on the OCS.
(7) Any producer operating a pipeline that connects facilities on
the OCS must comply with this subpart.
(8) Any operator of a pipeline that has a valve on the OCS
downstream (landward) of the last production facility may ask in writing
that the BSEE Regional Supervisor recognize that valve as the last point
BSEE will exercise its regulatory authority.
(9) A pipeline segment is not subject to BSEE regulations for
design, construction, operation, and maintenance if:
(i) It is downstream (generally shoreward) of the last valve and
associated safety equipment on the last production facility on the OCS;
and
(ii) It is subject to regulation under 49 CFR parts 192 and 195.
(10) DOT may inspect all upstream safety equipment (including
valves, over-pressure protection devices, cathodic protection equipment,
and pigging devices, etc.) that serve to protect

[[Page 208]]

the integrity of DOT-regulated pipeline segments.
(11) OCS pipeline segments not subject to DOT regulation under 49
CFR parts 192 and 195 are subject to all BSEE regulations.
(12) A producer may request that its pipeline operate under DOT
regulations governing pipeline design, construction, operation, and
maintenance.
(i) The operator's request must be in the form of a written petition
to the BSEE Regional Supervisor that states the justification for the
pipeline to operate under DOT regulation.
(ii) The Regional Supervisor will decide, on a case-by-case basis,
whether to grant the operator's request. In considering each petition,
the Regional Supervisor will consult with the appropriate DOT pipeline
official.
(13) A transporter who operates a pipeline regulated by DOT may
request to operate under BSEE regulations governing pipeline operation
and maintenance. Any subsequent repairs or modifications will also be
subject to BSEE regulations governing design and construction.
(i) The operator's request must be in the form of a written petition
to the appropriate DOT pipeline official and the BSEE Regional
Supervisor.
(ii) The BSEE Regional Supervisor and the appropriate DOT pipeline
official will decide how to act on this petition.
(d) A pipeline which qualifies as a right-of-way pipeline (see Sec.
250.1001, Definitions) shall not be installed until a right-of-way has
been requested and granted in accordance with this subpart.
(e)(1) The Regional Supervisor may suspend any pipeline operation
upon a determination by the Regional Supervisor that continued activity
would threaten or result in serious, irreparable, or immediate harm or
damage to life (including fish and other aquatic life), property,
mineral deposits, or the marine, coastal, or human environment.
(2) The Regional Supervisor may also suspend pipeline operations or
a right-of-way grant if the Regional Supervisor determines that the
lessee or right-of-way holder has failed to comply with a provision of
the Act or any other applicable law, a provision of these or other
applicable regulations, or a condition of a permit or right-of-way
grant.
(3) The Secretary of the Interior (Secretary) may cancel a pipeline
permit or right-of-way grant in accordance with 43 U.S.C. 1334(a)(2). A
right-of-way grant may be forfeited in accordance with 43 U.S.C.
1334(e).

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36150, June 6, 2016]

Sec. 250.1001 Definitions.

Terms used in this subpart shall have the meanings given below:
DOI pipelines include:
(1) Producer-operated pipelines extending upstream (generally
seaward) from each point on the OCS at which operating responsibility
transfers from a producing operator to a transporting operator;
(2) Producer-operated pipelines extending upstream (generally
seaward) of the last valve (including associated safety equipment) on
the last production facility on the OCS that do not connect to a
transporter-operated pipeline on the OCS before crossing into State
waters;
(3) Producer-operated pipelines connecting production facilities on
the OCS;
(4) Transporter-operated pipelines that DOI and DOT have agreed are
to be regulated as DOI pipelines; and
(5) All OCS pipelines not subject to regulation under 49 CFR parts
192 and 195.
DOT pipelines include:
(1) Transporter-operated pipelines currently operated under DOT
requirements governing design, construction, maintenance, and operation;
(2) Producer-operated pipelines that DOI and DOT have agreed are to
be regulated under DOT requirements governing design, construction,
maintenance, and operation; and
(3) Producer-operated pipelines downstream (generally shoreward) of
the last valve (including associated safety equipment) on the last
production facility on the OCS that do not connect to a transporter-
operated pipeline on the OCS before crossing into State waters and that
are regulated under 49 CFR parts 192 and 195.

[[Page 209]]

Lease term pipelines are those pipelines owned and operated by a
lessee or operator and are wholly contained within the boundaries of a
single lease, unitized leases, or contiguous (not cornering) leases of
that lessee or operator.
Out-of-service pipelines are those pipelines that have not been used
to transport oil, natural gas, sulfur, or produced water for more than
30 consecutive days.
Pipelines are the piping, risers, and appurtenances installed for
the purpose of transporting oil, gas, sulphur, and produced water.
(Piping confined to a production platform or structure is covered in
Subpart H, Production Safety Systems, and is excluded from this
subpart.)
Production facilities means OCS facilities that receive hydrocarbon
production either directly from wells or from other facilities that
produce hydrocarbons from wells. They may include processing equipment
for treating the production or separating it into its various liquid and
gaseous components before transporting it to shore.
Right-of-way pipelines are those pipelines which--
(1) Are contained within the boundaries of a single lease or group
of unitized leases but are not owned and operated by the lessee or
operator of that lease or unit,
(2) Are contained within the boundaries of contiguous (not
cornering) leases which do not have a common lessee or operator,
(3) Are contained within the boundaries of contiguous (not
cornering) leases which have a common lessee or operator but are not
owned and operated by that common lessee or operator, or
(4) Cross any portion of an unleased block(s).

Sec. 250.1002 Design requirements for DOI pipelines.

(a) The internal design pressure for steel pipe shall be determined
in accordance with the following formula:
[GRAPHIC] [TIFF OMITTED] TR18OC11.000

For limitations see section 841.121 of American National Standards
Institute (ANSI) B31.8 (as incorporated by reference in Sec. 250.198)
where--

P = Internal design pressure in pounds per square inch (psi).
S = Specified minimum yield strength, in psi, stipulated in the
specification under which the pipe was purchased from the
manufacturer or determined in accordance with section
811.253(h) of ANSI B31.8.
D = Nominal outside diameter of pipe, in inches.
t = Nominal wall thickness, in inches.
F = Construction design factor of 0.72 for the submerged component and
0.60 for the riser component.
E = Longitudinal joint factor obtained from Table 841.1B of ANSI B31.8
(see also section 811.253(d)).
T = Temperature derating factor obtained from Table 841.1C of ANSI
B31.8.

(b)(1) Pipeline valves shall meet the minimum design requirements of
American Petroleum Institute (API) Spec 6A (as incorporated by reference
in Sec. 250.198), API Spec 6D (as incorporated by reference in Sec.
250.198), or the equivalent. A valve may not be used under operating
conditions that exceed the applicable pressure-temperature ratings
contained in those standards.
(2) Pipeline flanges and flange accessories shall meet the minimum
design requirements of ANSI B16.5, API Spec 6A, or the equivalent (as
incorporated by reference in 30 CFR 250.198). Each flange assembly must
be able to withstand the maximum pressure at which the pipeline is to be
operated and to maintain its physical and chemical properties at any
temperature to which it is anticipated that it might be subjected in
service.
(3) Pipeline fittings shall have pressure-temperature ratings based
on stresses for pipe of the same or equivalent material. The actual
bursting strength of the fitting shall at least be equal to the computed
bursting strength of the pipe.
(4) If you are installing pipelines constructed of unbonded flexible
pipe, you must design them according to the standards and procedures of
API Spec 17J, as incorporated by reference in 30 CFR 250.198.
(5) You must design pipeline risers for tension leg platforms and
other

[[Page 210]]

floating platforms according to the design standards of API RP 2RD,
Design of Risers for Floating Production Systems (FPSs) and Tension Leg
Platforms (TLPs) (as incorporated by reference in Sec. 250.198).
(c) The maximum allowable operating pressure (MAOP) shall not exceed
the least of the following:
(1) Internal design pressure of the pipeline, valves, flanges, and
fittings;
(2) Eighty percent of the hydrostatic pressure test (HPT) pressure
of the pipeline; or
(3) If applicable, the MAOP of the receiving pipeline when the
proposed pipeline and the receiving pipeline are connected at a subsea
tie-in.
(d) If the maximum source pressure (MSP) exceeds the pipeline's
MAOP, you must install and maintain redundant safety devices meeting the
requirements of section A9 of API RP 14C (as incorporated by reference
in Sec. 250.198). Pressure safety valves (PSV) may be used only after a
determination by the Regional Supervisor that the pressure will be
relieved in a safe and pollution-free manner. The setting level at which
the primary and redundant safety equipment actuates shall not exceed the
pipeline's MAOP.
(e) Pipelines shall be provided with an external protective coating
capable of minimizing underfilm corrosion and a cathodic protection
system designed to mitigate corrosion for at least 20 years.
(f) Pipelines shall be designed and maintained to mitigate any
reasonably anticipated detrimental effects of water currents, storm or
ice scouring, soft bottoms, mud slides, earthquakes, subfreezing
temperatures, and other environmental factors.

Sec. 250.1003 Installation, testing, and repair requirements
for DOI pipelines.

(a)(1) Pipelines greater than 8\5/8\ inches in diameter and
installed in water depths of less than 200 feet shall be buried to a
depth of at least 3 feet unless they are located in pipeline congested
areas or seismically active areas as determined by the Regional
Supervisor. Nevertheless, the Regional Supervisor may require burial of
any pipeline if the Regional Supervisor determines that such burial will
reduce the likelihood of environmental degradation or that the pipeline
may constitute a hazard to trawling operations or other uses. A trawl
test or diver survey may be required to determine whether or not
pipeline burial is necessary or to determine whether a pipeline has been
properly buried.
(2) Pipeline valves, taps, tie-ins, capped lines, and repaired
sections that could be obstructive shall be provided with at least 3
feet of cover unless the Regional Supervisor determines that such items
present no hazard to trawling or other operations. A protective device
may be used to cover an obstruction in lieu of burial if it is approved
by the Regional Supervisor prior to installation.
(3) Pipelines shall be installed with a minimum separation of 18
inches at pipeline crossings and from obstructions.
(4) Pipeline risers installed after April 1, 1988, shall be
protected from physical damage that could result from contact with
floating vessels. Riser protection on pipelines installed on or before
April 1, 1988, may be required when the Regional Supervisor determines
that significant damage potential exists.
(b)(1) Pipelines shall be pressure tested with water at a stabilized
pressure of at least 1.25 times the MAOP for at least 8 hours when
installed, relocated, uprated, or reactivated after being out-of-service
for more than 1 year.
(2) Prior to returning a pipeline to service after a repair, the
pipeline shall be pressure tested with water or processed natural gas at
a minimum stabilized pressure of at least 1.25 times the MAOP for at
least 2 hours.
(3) Pipelines shall not be pressure tested at a pressure which
produces a stress in the pipeline in excess of 95 percent of the
specified minimum-yield strength of the pipeline. A temperature recorder
measuring test fluid temperature synchronized with a pressure recorder
along with deadweight test readings shall be employed for all pressure
testing. When a pipeline is pressure tested, no observable leakage shall
be allowed. Pressure gauges and recorders shall be of sufficient
accuracy to verify that leakage is not occurring.

[[Page 211]]

(4) The Regional Supervisor may require pressure testing of
pipelines to verify the integrity of the system when the Regional
Supervisor determines that there is a reasonable likelihood that the
line has been damaged or weakened by external or internal conditions.
(c) When a pipeline is repaired utilizing a clamp, the clamp shall
be a full encirclement clamp able to withstand the anticipated pipeline
pressure.

Sec. 250.1004 Safety equipment requirements for DOI pipelines.

(a) The lessee shall ensure the proper installation, operation, and
maintenance of safety devices required by this section on all incoming,
departing, and crossing pipelines on platforms.
(b)(1)(i) Incoming pipelines to a platform shall be equipped with a
flow safety valve (FSV).
(ii) For sulphur operations, incoming pipelines delivering gas to
the power plant platform may be equipped with high- and low-pressure
sensors (PSHL), which activate audible and visual alarms in lieu of
requirements in paragraph (b)(1)(i) of this section. The PSHL shall be
set at 15 percent or 5 psi, whichever is greater, above and below the
normal operating pressure range.
(2) Incoming pipelines boarding a production platform shall be
equipped with an automatic shutdown valve (SDV) immediately upon
boarding the platform. The SDV shall be connected to the automatic- and
remote-emergency shut-in systems.
(3) Departing pipelines receiving production from production
facilities shall be protected by high- and low-pressure sensors (PSHL)
to directly or indirectly shut in all production facilities. The PSHL
shall be set not to exceed 15 percent above and below the normal
operating pressure range. However, high pilots shall not be set above
the pipeline's MAOP.
(4) Crossing pipelines on production or manned nonproduction
platforms which do not receive production from the platform shall be
equipped with an SDV immediately upon boarding the platform. The SDV
shall be operated by a PSHL on the departing pipelines and connected to
the platform automatic- and remote-emergency shut-in systems.
(5) The Regional Supervisor may require that oil pipelines be
equipped with a metering system to provide a continuous volumetric
comparison between the input to the line at the structure(s) and the
deliveries onshore. The system shall include an alarm system and shall
be of adequate sensitivity to detect variations between input and
discharge volumes. In lieu of the foregoing, a system capable of
detecting leaks in the pipeline may be substituted with the approval of
the Regional Supervisor.
(6) Pipelines incoming to a subsea tie-in shall be equipped with a
block valve and an FSV. Bidirectional pipelines connected to a subsea
tie-in shall be equipped with only a block valve.
(7) Gas-lift or water-injection pipelines on unmanned platforms need
only be equipped with an FSV installed immediately upstream of each
casing annulus or the first inlet valve on the christmas tree.
(8) Bidirectional pipelines shall be equipped with a PSHL and an SDV
immediately upon boarding each platform.
(9) Pipeline pumps must comply with section A7 of API RP 14C (as
incorporated by reference in Sec. 250.198). The setting levels for the
PSHL devices are specified in paragraph (b)(3) of this section.
(c) If the required safety equipment is rendered ineffective or
removed from service on pipelines which are continued in operation, an
equivalent degree of safety shall be provided. The safety equipment
shall be identified by the placement of a sign on the equipment stating
that the equipment is rendered ineffective or removed from service.

Sec. 250.1005 Inspection requirements for DOI pipelines.

(a) Pipeline routes shall be inspected at time intervals and methods
prescribed by the Regional Supervisor for indication of pipeline
leakage. The results of these inspections shall be retained for at least
2 years and be made available to the Regional Supervisor upon request.

[[Page 212]]

(b) When pipelines are protected by rectifiers or anodes for which
the initial life expectancy of the cathodic protection system either
cannot be calculated or calculations indicate a life expectancy of less
than 20 years, such pipelines shall be inspected annually by taking
measurements of pipe-to-electrolyte potential.

Sec. 250.1006 How must I decommission and take out of service
a DOI pipeline?

(a) The requirements for decommissioning pipelines are listed in
Sec. 250.1750 through Sec. 250.1754.
(b) The table in this section lists the requirements if you take a
DOI pipeline out of service:

----------------------------------------------------------------------------------------------------------------
If you have the pipeline out of service for: Then you must:
----------------------------------------------------------------------------------------------------------------
(1) 1 year or less, Isolate the pipeline with a blind flange or a closed block
valve at each end of the pipeline.
(2) More than 1 year but less than 5 years, Flush and fill the pipeline with inhibited seawater.
(3) 5 or more years, Decommission the pipeline according to Sec. Sec.
250.1750-250.1754.
----------------------------------------------------------------------------------------------------------------

Sec. 250.1007 What to include in applications.

(a) Applications to install a lease term pipeline or for a pipeline
right-of-way grant must be submitted in quadruplicate to the Regional
Supervisor. Right-of-way grant applications must include an
identification of the operator of the pipeline. Each application must
include the following:
(1) Plat(s) drawn to a scale specified by the Regional Supervisor
showing major features and other pertinent data including area, lease,
and block designations; water depths; route; length in Federal waters;
width of right-of-way, if applicable; connecting facilities; size;
product(s) to be transported with anticipated gravity or density; burial
depth; direction of flow; X-Y coordinates of key points; and the
location of other pipelines that will be connected to or crossed by the
proposed pipeline(s). The initial and terminal points of the pipeline
and any continuation into State jurisdiction shall be accurately located
even if the pipeline is to have an onshore terminal point. A plat(s)
submitted for a pipeline right-of-way shall bear a signed certificate
upon its face by the engineer who made the map that certifies that the
right-of-way is accurately represented upon the map and that the design
characteristics of the associated pipeline are in accordance with
applicable regulations.
(2) A schematic drawing showing the size, weight, grade, wall
thickness, and type of line pipe and risers; pressure-regulating devices
(including back-pressure regulators); sensing devices with associated
pressure-control lines; PSV's and settings; SDV's, FSV's, and block
valves; and manifolds. This schematic drawing shall also show input
source(s), e.g., wells, pumps, compressors, and vessels; maximum input
pressure(s); the rated working pressure, as specified by ANSI or API, of
all valves, flanges, and fittings; the initial receiving equipment and
its rated working pressure; and associated safety equipment and pig
launchers and receivers. The schematic must indicate the point on the
OCS at which operating responsibility transfers between a producing
operator and a transporting operator.
(3) General information as follows:
(i) Description of cathodic protection system. If pipeline anodes
are to be used, specify the type, size, weight, number, spacing, and
anticipated life;
(ii) Description of external pipeline coating system;
(iii) Description of internal protective measures;
(iv) Specific gravity of the empty pipe;
(v) MSP;
(vi) MAOP and calculations used in its determination;
(vii) Hydrostatic test pressure, medium, and period of time that the
line will be tested;
(viii) MAOP of the receiving pipeline or facility,
(ix) Proposed date for commencing installation and estimated time
for construction; and
(x) Type of protection to be afforded crossing pipelines, subsea
valves, taps, and manifold assemblies, if applicable.

[[Page 213]]

(4) A description of any additional design precautions you took to
enable the pipeline to withstand the effects of water currents, storm or
ice scouring, soft bottoms, mudslides, earthquakes, permafrost, and
other environmental factors.
(i) If you propose to use unbonded flexible pipe, your application
must include:
(A) The manufacturer's design specification sheet;
(B) The design pressure (psi);
(C) An identification of the design standards you used; and
(D) A review by a third-party independent verification agent (IVA)
according to API Spec 17J (as incorporated by reference in Sec.
250.198), if applicable.
(ii) If you propose to use one or more pipeline risers for a tension
leg platform or other floating platform, your application must include:
(A) The design fatigue life of the riser, with calculations, and the
fatigue point at which you would replace the riser;
(B) The results of your vortex-induced vibration (VIV) analysis;
(C) An identification of the design standards you used; and
(D) A description of any necessary mitigation measures such as the
use of helical strakes or anchoring devices.
(5) The application shall include a shallow hazards survey report
and, if required by the Regional Director, an archaeological resource
report that covers the entire length of the pipeline. A shallow hazards
analysis may be included in a lease term pipeline application in lieu of
the shallow hazards survey report with the approval of the Regional
Director. The Regional Director may require the submission of the data
upon which the report or analysis is based.
(b) Applications to modify an approved lease term pipeline or right-
of-way grant shall be submitted in quadruplicate to the Regional
Supervisor. These applications need only address those items in the
original application affected by the proposed modification.

Sec. 250.1008 Reports.

(a) The lessee, or right-of-way holder, shall notify the Regional
Supervisor at least 48 hours prior to commencing the installation or
relocation of a pipeline or conducting a pressure test on a pipeline.
(b) The lessee or right-of-way holder shall submit a report to the
Regional Supervisor within 90 days after completion of any pipeline
construction. The report, submitted in triplicate, shall include an
``as-built'' location plat drawn to a scale specified by the Regional
Supervisor showing the location, length in Federal waters, and X-Y
coordinates of key points; the completion date; the proposed date of
first operation; and the HPT data. Pipeline right-of-way ``as-built''
location plats shall be certified by a registered engineer or land
surveyor and show the boundaries of the right-of-way as granted. If
there is a substantial deviation of the pipeline route as granted in the
right-of-way, the report shall include a discussion of the reasons for
such deviation.
(c) The lessee or right-of-way holder shall report to the Regional
Supervisor any pipeline taken out of service. If the period of time in
which the pipeline is out of service is greater than 60 days, written
confirmation is also required.
(d) The lessee or right-of-way holder shall report to the Regional
Supervisor when any required pipeline safety equipment is taken out of
service for more than 12 hours. The Regional Supervisor shall be
notified when the equipment is returned to service.
(e) The lessee or right-of-way holder must notify the Regional
Supervisor before the repair of any pipeline or as soon as practicable.
Your notification must be accompanied by payment of the service fee
listed in Sec. 250.125. You must submit a detailed report of the repair
of a pipeline or pipeline component to the Regional Supervisor within 30
days after the completion of the repairs. In the report you must include
the following:
(1) Description of repairs;
(2) Results of pressure test; and
(3) Date returned to service.
(f) The Regional Supervisor may require that DOI pipeline failures
be analyzed and that samples of a failed section be examined in a
laboratory to assist in determining the cause of the

[[Page 214]]

failure. A comprehensive written report of the information obtained
shall be submitted by the lessee to the Regional Supervisor as soon as
available.
(g) If the effects of scouring, soft bottoms, or other environmental
factors are observed to be detrimentally affecting a pipeline, a plan of
corrective action shall be submitted to the Regional Supervisor for
approval within 30 days of the observation. A report of the remedial
action taken shall be submitted to the Regional Supervisor by the lessee
or right-of-way holder within 30 days after completion.
(h) The results and conclusions of measurements of pipe-to-
electrolyte potential measurements taken annually on DOI pipelines in
accordance with Sec. 250.1005(b) of this part shall be submitted to the
Regional Supervisor by the lessee before March of each year.

Sec. 250.1009 Requirements to obtain pipeline right-of-way grants.

(a) In addition to applicable requirements of Sec. Sec. 250.1000
through 250.1008 and other regulations of this part, regulations of the
Department of Transportation, Department of the Army, and the Federal
Energy Regulatory Commission (FERC), when a pipeline qualifies as a
right-of-way pipeline, the pipeline shall not be installed until a
right-of-way has been requested and granted in accordance with this
subpart. The right-of-way grant is issued pursuant to 43 U.S.C. 1334(e)
and may be acquired and held only by citizens and nationals of the
United States; aliens lawfully admitted for permanent residence in the
United States as defined in 8 U.S.C. 1101(a)(20); private, public, or
municipal corporations organized under the laws of the United States or
territory thereof, the District of Columbia, or of any State; or
associations of such citizens, nationals, resident aliens, or private,
public, or municipal corporations, States, or political subdivisions of
States.
(b) A right-of-way shall include the site on which the pipeline and
associated structures are to be situated, shall not exceed 200 feet in
width unless safety and environmental factors during construction and
operation of the associated right-of-way pipeline require a greater
width, and shall be limited to the area reasonably necessary for pumping
stations or other accessory structures.

Sec. 250.1010 General requirements for pipeline right-of-way holders.

An applicant, by accepting a right-of-way grant, agrees to comply
with the following requirements:
(a) The right-of-way holder shall comply with applicable laws and
regulations and the terms of the grant.
(b) The granting of the right-of-way shall be subject to the express
condition that the rights granted shall not prevent or interfere in any
way with the management, administration, or the granting of other rights
by the United States, either prior or subsequent to the granting of the
right-of-way. Moreover, the holder agrees to allow the occupancy and use
by the United States, its lessees, or other right-of-way holders, of any
part of the right-of-way grant not actually occupied or necessarily
incident to its use for any necessary operations involved in the
management, administration, or the enjoyment of such other granted
rights.
(c) If the right-of-way holder discovers any archaeological resource
while conducting operations within the right-of-way, the right-of-way
holder shall immediately halt operations within the area of the
discovery and report the discovery to the Regional Director. If
investigations determine that the resource is significant, the Regional
Director will inform the right-of-way holder how to protect it.
(d) The Regional Supervisor shall be kept informed at all times of
the right-of-way holder's address and, if a corporation, the address of
its principal place of business and the name and address of the officer
or agent authorized to be served with process.
(e) The right-of-way holder shall pay the United States or its
lessees or right-of-way holders, as the case may be, the full value of
all damages to the property of the United States or its said lessees or
right-of-way holders and shall indemnify the United States against any
and all liability for damages to life, person, or property arising

[[Page 215]]

from the occupation and use of the area covered by the right-of-way
grant.
(f)(1) The holder of a right-of-way oil or gas pipeline shall
transport or purchase oil or natural gas produced from submerged lands
in the vicinity of the pipeline without discrimination and in such
proportionate amounts as the FERC may, after a full hearing with due
notice thereof to the interested parties, determine to be reasonable,
taking into account, among other things, conservation and the prevention
of waste.
(2) Unless otherwise exempted by FERC pursuant to 43 U.S.C.
1334(f)(2), the holder shall:
(i) Provide open and nondiscriminatory access to a right-of-way
pipeline to both owner and nonowner shippers, and
(ii) Comply with the provisions of 43 U.S.C. 1334(f)(1)(B) under
which FERC may order an expansion of the throughput capacity of a right-
of-way pipeline which is approved after September 18, 1978, and which is
not located in the Gulf of Mexico or the Santa Barbara Channel.
(g) The area covered by a right-of-way and all improvements thereon
shall be kept open at all reasonable times for inspection by the Bureau
of Safety and Environmental Enforcement (BSEE). The right-of-way holder
shall make available all records relative to the design, construction,
operation, maintenance and repair, and investigations on or with regard
to such area.
(h) Upon relinquishment, forfeiture, or cancellation of a right-of-
way grant, the right-of-way holder shall remove all platforms,
structures, domes over valves, pipes, taps, and valves along the right-
of-way. All of these improvements shall be removed by the holder within
1 year of the effective date of the relinquishment, forfeiture, or
cancellation unless this requirement is waived in writing by the
Regional Supervisor. All such improvements not removed within the time
provided herein shall become the property of the United States but that
shall not relieve the holder of liability for the cost of their removal
or for restoration of the site. Furthermore, the holder is responsible
for accidents or damages which might occur as a result of failure to
timely remove improvements and equipment and restore a site. An
application for relinquishment of a right-of-way grant shall be filed in
accordance with Sec. 250.1019 of this part.

Sec. 250.1011 [Reserved]

Sec. 250.1012 Required payments for pipeline right-of-way holders.

(a) You must pay ONRR, under the regulations at 30 CFR part 1218, an
annual rental of $15 for each statute mile, or part of a statute mile,
of the OCS that your pipeline right-of-way crosses.
(b) This paragraph applies to you if you obtain a pipeline right-of-
way that includes a site for an accessory to the pipeline, including but
not limited to a platform. This paragraph also applies if you apply to
modify a right-of-way to change the site footprint. In either case, you
must pay the amounts shown in the following table.

----------------------------------------------------------------------------------------------------------------
If . . . Then . . .
----------------------------------------------------------------------------------------------------------------
(1) Your accessory site is located in water depths You must pay ONRR, under the regulations at 30 CFR part
of less than 200 meters; 1218, a rental of $5 per acre per year with a minimum of
$450 per year. The area subject to annual rental includes
the areal extent of anchor chains, pipeline risers, and
other facilities and devices associated with the
accessory.
(2) Your accessory site is located in water depths You must pay ONRR, under the regulations at 30 CFR part
of 200 meters or greater; 1218, a rental of $7.50 per acre per year with a minimum
of $675 per year. The area subject to annual rental
includes the areal extent of anchor chains, pipeline
risers, and other facilities and devices associated with
the accessory.
----------------------------------------------------------------------------------------------------------------

(c) If you hold a pipeline right-of-way that includes a site for an
accessory to your pipeline and you are not covered by paragraph (b) of
this section, then you must pay ONRR, under the regulations at 30 CFR
part 1218, an annual rental of $75 for use of the affected area.
(d) You may make the rental payments required by paragraphs (a),
(b)(1), (b)(2), and (c) of this section on an annual basis, for a 5-year
period, or

[[Page 216]]

for multiples of 5 years. You must make the first payment at the time
you submit the pipeline right-of-way application. You must make all
subsequent payments before the respective time periods begin.
(e) Late payments. An interest charge will be assessed on unpaid and
underpaid amounts from the date the amounts are due, in accordance with
the provisions found in 30 CFR 1218.54. If you fail to make a payment
that is late after written notice from ONRR, BSEE may initiate
cancellation of the right-of-use grant and easement under Sec.
250.1013.

Sec. 250.1013 Grounds for forfeiture of pipeline right-of-way grants.

Failure to comply with the Act, regulations, or any conditions of
the right-of-way grant prescribed by the Regional Supervisor shall be
grounds for forfeiture of the grant in an appropriate judicial
proceeding instituted by the United States in any U.S. District Court
having jurisdiction in accordance with the provisions of 43 U.S.C. 1349.

Sec. 250.1014 When pipeline right-of-way grants expire.

Any right-of-way granted under the provisions of this subpart
remains in effect as long as the associated pipeline is properly
maintained and used for the purpose for which the grant was made, unless
otherwise expressly stated in the grant. Temporary cessation or
suspension of pipeline operations shall not cause the grant to expire.
However, if the purpose of the grant ceases to exist or use of the
associated pipeline is permanently discontinued for any reason, the
grant shall be deemed to have expired.

Sec. 250.1015 Applications for pipeline right-of-way grants.

(a) You must submit an original and three copies of an application
for a new or modified pipeline ROW grant to the Regional Supervisor. The
application must address those items required by Sec. 250.1007(a) or
(b) of this subpart, as applicable. It must also state the primary
purpose for which you will use the ROW grant. If the ROW has been used
before the application is made, the application must state the date such
use began, by whom, and the date the applicant obtained control of the
improvement. When you file your application, you must pay the rental
required under Sec. 250.1012 of this subpart, as well as the service
fees listed in Sec. 250.125 of this part for a pipeline ROW grant to
install a new pipeline, or to convert an existing lease term pipeline
into a ROW pipeline. An application to modify an approved ROW grant must
be accompanied by the additional rental required under Sec. 250.1012 if
applicable. You must file a separate application for each ROW.
(b)(1) An individual applicant shall submit a statement of
citizenship or nationality with the application. An applicant who is an
alien lawfully admitted for permanent residence in the United States
shall also submit evidence of such status with the application.
(2) If the applicant is an association (including a partnership),
the application shall also be accompanied by a certified copy of the
articles of association or appropriate reference to a copy of such
articles already filed with BSEE and a statement as to any subsequent
amendments.
(3) If the applicant is a corporation, the application shall also
include the following:
(i) A statement certified by the Secretary or Assistant Secretary of
the corporation with the corporate seal showing the State in which it is
incorporated and the name of the person(s) authorized to act on behalf
of the corporation, or
(ii) In lieu of such a statement, an appropriate reference to
statements or records previously submitted to BSEE (including material
submitted in compliance with prior regulations).
(c) The application shall include a list of every lessee and right-
of-way holder whose lease or right-of-way is intersected by the proposed
right-of-way. The application shall also include a statement that a copy
of the application has been sent by registered or certified mail to each
such lessee or right-of-way holder.
(d) The applicant shall include in the application an original and
three copies of a completed Nondiscrimination

[[Page 217]]

in Employment form (YN 3341-1 dated July 1982). These forms are
available at each BSEE regional office.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36150, June 6, 2016]

Sec. 250.1016 Granting pipeline rights-of-way.

(a) In considering an application for a right-of-way, the Regional
Supervisor shall consider the potential effect of the associated
pipeline on the human, marine, and coastal environments, life (including
aquatic life), property, and mineral resources in the entire area during
construction and operational phases. The Regional Supervisor shall
prepare an environmental analysis in accordance with applicable policies
and guidelines. To aid in the evaluation and determinations, the
Regional Supervisor may request and consider views and recommendations
of appropriate Federal Agencies, hold public meetings after appropriate
notice, and consult, as appropriate, with State agencies, organizations,
industries, and individuals. Before granting a pipeline right-of-way,
the Regional Supervisor shall give consideration to any recommendation
by the intergovernmental planning program, or similar process, for the
assessment and management of OCS oil and gas transportation.
(b) Should the proposed route of a right-of-way adjoin and
subsequently cross any State submerged lands, the applicant shall submit
evidence to the Regional Supervisor that the State(s) so affected has
reviewed the application. The applicant shall also submit any comment
received as a result of that review. In the event of a State
recommendation to relocate the proposed route, the Regional Supervisor
may consult with the appropriate State officials.
(c)(1) The applicant shall submit photocopies of return receipts to
the Regional Supervisor that indicate the date that each lessee or
right-of-way holder referenced in Sec. 250.1015(c) of this part has
received a copy of the application. Letters of no objection may be
submitted in lieu of the return receipts.
(2) The Regional Supervisor shall not take final action on a right-
of-way application until the Regional Supervisor is satisfied that each
such lessee or right-of-way holder has been afforded at least 30 days
from the date determined in paragraph (c)(1) of this section in which to
submit comments.
(d) If a proposed right-of-way crosses any lands not subject to
disposition by mineral leasing or restricted from oil and gas
activities, it shall be rejected by the Regional Supervisor unless the
Federal Agency with jurisdiction over such excluded or restricted area
gives its consent to the granting of the right-of-way. In such case, the
applicant, upon a request filed within 30 days after receipt of the
notification of such rejection, shall be allowed an opportunity to
eliminate the conflict.
(e)(1) If the application and other required information are found
to be in compliance with applicable laws and regulations, the right-of-
way may be granted. The Regional Supervisor may prescribe, as conditions
to the right-of-way grant, stipulations necessary to protect human,
marine, and coastal environments, life (including aquatic life),
property, and mineral resources located on or adjacent to the right-of-
way.
(2) If the Regional Supervisor determines that a change in the
application should be made, the Regional Supervisor shall notify the
applicant that an amended application shall be filed subject to
stipulated changes. The Regional Supervisor shall determine whether the
applicant shall deliver copies of the amended application to other
parties for comment.
(3) A decision to reject an application shall be in writing and
shall state the reasons for the rejection.

Sec. 250.1017 Requirements for construction under pipeline
right-of-way grants.

(a) Failure to construct the associated right-of-way pipeline within
5 years of the date of the granting of a right-of-way shall cause the
grant to expire.
(b)(1) A right-of-way holder shall ensure that the right-of-way
pipeline is constructed in a manner that minimizes deviations from the
right-of-way as granted.

[[Page 218]]

(2) If, after constructing the right-of-way pipeline, it is
determined that a deviation from the proposed right-of-way as granted
has occurred, the right-of-way holder shall--
(i) Notify the operators of all leases and holders of all right-of-
way grants in which a deviation has occurred, and within 60 days of the
date of the acceptance by the Regional Supervisor of the completion of
pipeline construction report, provide the Regional Supervisor with
evidence of such notification; and
(ii) Relinquish any unused portion of the right-of-way.
(3) Substantial deviation of a right-of-way pipeline as constructed
from the proposed right-of-way as granted may be grounds for forfeiture
of the right-of-way.
(c) If the Regional Supervisor determines that a significant change
in conditions has occurred subsequent to the granting of a right-of-way
but prior to the commencement of construction of the associated
pipeline, the Regional Supervisor may suspend or temporarily prohibit
the commencement of construction until the right-of-way grant is
modified to the extent necessary to address the changed conditions.

Sec. 250.1018 Assignment of pipeline right-of-way grants.

(a) Assignment may be made of a right-of-way grant, in whole or of
any lineal segment thereof, subject to the approval of the Regional
Supervisor. An application for approval of an assignment of a right-of-
way or of a lineal segment thereof, shall be filed in triplicate with
the Regional Supervisor.
(b) Any application for approval for an assignment, in whole or in
part, of any right, title, or interest in a right-of-way grant must be
accompanied by the same showing of qualifications of the assignees as is
required of an applicant for a ROW in Sec. 250.1015 of this subpart and
must be supported by a statement that the assignee agrees to comply with
and to be bound by the terms and conditions of the ROW grant. The
assignee must satisfy the bonding requirements in 30 CFR 550.1011. No
transfer will be recognized unless and until it is first approved, in
writing, by the Regional Supervisor. The assignee must pay the service
fee listed in Sec. 250.125 of this part for a pipeline ROW assignment
request.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36150, June 6, 2016]

Sec. 250.1019 Relinquishment of pipeline right-of-way grants.

A right-of-way grant or a portion thereof may be surrendered by the
holder by filing a written relinquishment in triplicate with the
Regional Supervisor. It must contain those items addressed in Sec. Sec.
250.1751 and 250.1752 of this part. A relinquishment shall take effect
on the date it is filed subject to the satisfaction of all outstanding
debts, fees, or fines and the requirements in Sec. 250.1010(h) of this
part.

Subpart K_Oil and Gas Production Requirements

General

Sec. 250.1150 What are the general reservoir production requirements?

You must produce wells and reservoirs at rates that provide for
economic development while maximizing ultimate recovery and without
adversely affecting correlative rights.

Well Tests and Surveys

Sec. 250.1151 How often must I conduct well production tests?

(a) You must conduct well production tests as shown in the following
table:

------------------------------------------------------------------------
And you must submit to the
You must conduct: Regional Supervisor:
------------------------------------------------------------------------
(1) A well-flow potential test on all new, Form BSEE-0126, Well
recompleted, or reworked well completions Potential Test Report,
within 30 days of the date of first along with the supporting
continuous production, data as listed in the table
in Sec. 250.1167, within
15 days after the end of
the test period.
(2) At least one well test during a Results on Form BSEE-0128,
calendar half-year for each producing Semiannual Well Test
completion, Report, of the most recent
well test obtained. This
must be submitted within 45
days after the end of the
calendar half-year.
------------------------------------------------------------------------

[[Page 219]]

(b) You may request an extension from the Regional Supervisor if you
cannot submit the results of a semiannual well test within the specified
time.
(c) You must submit to the Regional Supervisor an original and two
copies of the appropriate form required by paragraph (a) of this
section; one of the copies of the form must be a public information copy
in accordance with Sec. Sec. 250.186 and 250.197, and marked ``Public
Information.'' You must submit two copies of the supporting information
as listed in the table in Sec. 250.1167 with form BSEE-0126.

Sec. 250.1152 How do I conduct well tests?

(a) When you conduct well tests you must:
(1) Recover fluid from the well completion equivalent to the amount
of fluid introduced into the formation during completion, recompletion,
reworking, or treatment operations before you start a well test;
(2) Produce the well completion under stabilized rate conditions for
at least 6 consecutive hours before beginning the test period;
(3) Conduct the test for at least 4 consecutive hours;
(4) Adjust measured gas volumes to the standard conditions of 14.73
pounds per square inch absolute (psia) and 60 [deg]F for all tests; and
(5) Use measured specific gravity values to calculate gas volumes.
(b) You may request approval from the Regional Supervisor to conduct
a well test using alternative procedures if you can demonstrate test
reliability under those procedures.
(c) The Regional Supervisor may also require you to conduct the
following tests and complete them within a specified time period:
(1) A retest or a prolonged test of a well completion if it is
determined to be necessary for the proper establishment of a Maximum
Production Rate (MPR) or a Maximum Efficient Rate (MER); and
(2) A multipoint back-pressure test to determine the theoretical
open-flow potential of a gas well.
(d) A BSEE representative may witness any well test. Upon request,
you must provide advance notice to the Regional Supervisor of the times
and dates of well tests.

Sec. Sec. 250.1153-250.1155 [Reserved]

Approvals Prior to Production

Sec. 250.1156 What steps must I take to receive approval to produce
within 500 feet of a unit or lease line?

(a) You must obtain approval from the Regional Supervisor before you
start producing from a reservoir within a well that has any portion of
the completed interval less than 500 feet from a unit or lease line.
Submit to BSEE the service fee listed in Sec. 250.125, according to the
instructions in Sec. 250.126, and the supporting information, as listed
in the table in Sec. 250.1167, with your request. The Regional
Supervisor will determine whether approval of your request will maximize
ultimate recovery, avoid the waste of natural resources, or protect
correlative rights. You do not need to obtain approval if the adjacent
leases or units have the same unit, lease (record title and operating
rights), and royalty interests as the lease or unit you plan to produce.
You do not need to obtain approval if the adjacent block is unleased.
(b) You must notify the operator(s) of adjacent property(ies) that
are within 500 feet of the completion, if the adjacent acreage is a
leased block in the Federal OCS. You must provide the Regional
Supervisor proof of the date of the notification. The operators of the
adjacent properties have 30 days after receiving the notification to
provide the Regional Supervisor letters of acceptance or objection. If
an adjacent operator does not respond within 30 days, the Regional
Supervisor will presume there are no objections and proceed with a
decision. The notification must include:
(1) The well name;
(2) The rectangular coordinates (x, y) of the location of the top
and bottom of the completion or target completion referenced to the
North American Datum 1983, and the subsea depths of the top and bottom
of the completion or target completion;
(3) The distance from the completion or target completion to the
unit or lease line at its nearest point; and

[[Page 220]]

(4) A statement indicating whether or not it will be a high-capacity
completion having a perforated or open hole interval greater than 150
feet measured depth.

Sec. 250.1157 How do I receive approval to produce gas-cap gas
from an oil reservoir with an associated gas cap?

(a) You must request and receive approval from the Regional
Supervisor:
(1) Before producing gas-cap gas from each completion in an oil
reservoir that is known to have an associated gas cap.
(2) To continue production from a well if the oil reservoir is not
initially known to have an associated gas cap, but the oil well begins
to show characteristics of a gas well.
(b) For either request, you must submit the service fee listed in
Sec. 250.125, according to the instructions in Sec. 250.126, and the
supporting information, as listed in the table in Sec. 250.1167, with
your request.
(c) The Regional Supervisor will determine whether your request
maximizes ultimate recovery.

Sec. 250.1158 How do I receive approval to downhole commingle hydrocarbons?

(a) Before you perforate a well, you must request and receive
approval from the Regional Supervisor to commingle hydrocarbons produced
from multiple reservoirs within a common wellbore. The Regional
Supervisor will determine whether your request maximizes ultimate
recovery. You must include the service fee listed in Sec. 250.125,
according to the instructions in Sec. 250.126, and the supporting
information, as listed in the table in Sec. 250.1167, with your
request.
(b) If one or more of the reservoirs proposed for commingling is a
competitive reservoir, you must notify the operators of all leases that
contain the reservoir that you intend to downhole commingle the
reservoirs. Your request for approval of downhole commingling must
include proof of the date of this notification. The notified operators
have 30 days after notification to provide the Regional Supervisor with
letters of acceptance or objection. If the notified operators do not
respond within the specified period, the Regional Supervisor will assume
the operators do not object and proceed with a decision.

Production Rates

Sec. 250.1159 May the Regional Supervisor limit my well
or reservoir production rates?

(a) The Regional Supervisor may set a Maximum Production Rate (MPR)
for a producing well completion, or set a Maximum Efficient Rate (MER)
for a reservoir, or both, if the Regional Supervisor determines that an
excessive production rate could harm ultimate recovery. An MPR or MER
will be based on well tests and any limitations imposed by well and
surface equipment, sand production, reservoir sensitivity, gas-oil and
water-oil ratios, location of perforated intervals, and prudent
operating practices.
(b) If the Regional Supervisor sets an MPR for a producing well
completion and/or an MER for a reservoir, you may not exceed those rates
except due to normal variations and fluctuations in production rates as
set by the Regional Supervisor.

Flaring, Venting, and Burning Hydrocarbons

Sec. 250.1160 When may I flare or vent gas?

(a) You must request and receive approval from the Regional
Supervisor to flare or vent natural gas at your facility, except in the
following situations:

------------------------------------------------------------------------
Condition Additional requirements
------------------------------------------------------------------------
(1) When the gas is lease use gas The volume of gas flared or
(produced natural gas which is used on vented may not exceed the
or for the benefit of lease operations amount necessary for its
such as gas used to operate production intended purpose. Burning
facilities) or is used as an additive waste products may require
necessary to burn waste products, such approval under other
as H2S. regulations.
(2) During the restart of a facility Flaring or venting may not
that was shut in because of weather exceed 48 cumulative hours
conditions, such as a hurricane. without Regional Supervisor
approval.

[[Page 221]]

(3) During the blow down of (i) You must report the
transportation pipelines downstream of location, time, flare/vent
the royalty meter. volume, and reason for flaring/
venting to the Regional
Supervisor in writing within
72 hours after the incident is
over.
(ii) Additional approval may be
required under subparts H and
J of this part.
(4) During the unloading or cleaning of You may not exceed 48
a well, drill-stem testing, production cumulative hours of flaring or
testing, other well-evaluation venting per unloading or
testing, or the necessary blow down to cleaning or testing operation
perform these procedures. on a single completion without
Regional Supervisor approval.
(5) When properly working equipment You may not flare or vent more
yields flash gas (natural gas released than an average of 50 MCF per
from liquid hydrocarbons as a result day during any calendar month
of a decrease in pressure, an increase without Regional Supervisor
in temperature, or both) from storage approval.
vessels or other low-pressure
production vessels, and you cannot
economically recover this flash gas.
(6) When the equipment works properly (i) For oil-well gas and gas-
but there is a temporary upset well flash gas (natural gas
condition, such as a hydrate or released from condensate as a
paraffin plug. result of a decrease in
pressure, an increase in
temperature, or both), you may
not exceed 48 continuous hours
of flaring or venting without
Regional Supervisor approval.
(ii) For primary gas-well gas
(natural gas from a gas well
completion that is at or near
its wellhead pressure; this
does not include flash gas),
you may not exceed 2
continuous hours of flaring or
venting without Regional
Supervisor approval.
(iii) You may not exceed 144
cumulative hours of flaring or
venting during a calendar
month without Regional
Supervisor approval.
(7) When equipment fails to work (i) For oil-well gas and gas-
properly, during equipment maintenance well flash gas, you may not
and repair, or when you must relieve exceed 48 continuous hours of
system pressures. flaring or venting without
Regional Supervisor approval.
(ii) For primary gas-well gas,
you may not exceed 2
continuous hours of flaring or
venting without Regional
Supervisor approval.
(iii) You may not exceed 144
cumulative hours of flaring or
venting during a calendar
month without Regional
Supervisor approval.
(iv) The continuous and
cumulative hours allowed under
this paragraph may be counted
separately from the hours
under paragraph (a)(6) of this
section.
------------------------------------------------------------------------

(b) Regardless of the requirements in paragraph (a) of this section,
you must not flare or vent gas over the volume approved in your
Development Operations Coordination Document (DOCD) or your Development
and Production Plan (DPP) submitted to BOEM.
(c) The Regional Supervisor may establish alternative approval
procedures to cover situations when you cannot contact the BSEE office,
such as during non-office hours.
(d) The Regional Supervisor may specify a volume limit, or a shorter
time limit than specified elsewhere in this part, in order to prevent
air quality degradation or loss of reserves.
(e) If you flare or vent gas without the required approval, or if
the Regional Supervisor determines that you were negligent or could have
avoided flaring or venting the gas, the hydrocarbons will be considered
avoidably lost or wasted. You must pay royalties on the loss or waste,
according to 30 CFR part 1202. You must value any gas or liquid
hydrocarbons avoidably lost or wasted under the provisions of 30 CFR
part 1206.
(f) Fugitive emissions from valves, fittings, flanges, pressure
relief valves or similar components do not require approval under this
subpart unless specifically required by the Regional Supervisor.

Sec. 250.1161 When may I flare or vent gas for extended periods of time?

You must request and receive approval from the Regional Supervisor
to flare or vent gas for an extended period of time. The Regional
Supervisor will specify the approved period of time, which will not
exceed 1 year. The Regional Supervisor may deny your request if it does
not ensure the conservation of natural resources or is not consistent
with National interests relating to development and production of
minerals of the OCS. The Regional Supervisor may approve your request
for one of the following reasons:

[[Page 222]]

(a) You initiated an action which, when completed, will eliminate
flaring and venting; or
(b) You submit to the Regional Supervisor an evaluation supported by
engineering, geologic, and economic data indicating that the oil and gas
produced from the well(s) will not economically support the facilities
necessary to sell the gas or to use the gas on or for the benefit of the
lease.

Sec. 250.1162 When may I burn produced liquid hydrocarbons?

(a) You must request and receive approval from the Regional
Supervisor to burn any produced liquid hydrocarbons. The Regional
Supervisor may allow you to burn liquid hydrocarbons if you demonstrate
that transporting them to market or re-injecting them is not technically
feasible or poses a significant risk of harm to offshore personnel or
the environment.
(b) If you burn liquid hydrocarbons without the required approval,
or if the Regional Supervisor determines that you were negligent or
could have avoided burning liquid hydrocarbons, the hydrocarbons will be
considered avoidably lost or wasted. You must pay royalties on the loss
or waste, according to 30 CFR part 1202. You must value any liquid
hydrocarbons avoidably lost or wasted under the provisions of 30 CFR
part 1206.

Sec. 250.1163 How must I measure gas flaring or venting volumes
and liquid hydrocarbon burning volumes, and what records must I maintain?

(a) If your facility processes more than an average of 2,000 bopd
during May 2010, you must install flare/vent meters within 180 days
after May 2010. If your facility processes more than an average of 2,000
bopd during a calendar month after May 2010, you must install flare/vent
meters within 120 days after the end of the month in which the average
amount of oil processed exceeds 2,000 bopd.
(1) You must notify the Regional Supervisor when your facility
begins to process more than an average of 2,000 bopd in a calendar
month;
(2) The flare/vent meters must measure all flared and vented gas
within 5 percent accuracy;
(3) You must calibrate the meters regularly, in accordance with the
manufacturer's recommendation, or at least once every year, whichever is
shorter; and
(4) You must use and maintain the flare/vent meters for the life of
the facility.
(b) You must report all hydrocarbons produced from a well
completion, including all gas flared, gas vented, and liquid
hydrocarbons burned, to Office of Natural Resources Revenue on Form
ONRR-4054 (Oil and Gas Operations Report), in accordance with 30 CFR
1210.102.
(1) You must report the amount of gas flared and the amount of gas
vented separately.
(2) You may classify and report gas used to operate equipment on the
lease, such as gas used to power engines, instrument gas, and gas used
to maintain pilot lights, as lease use gas.
(3) If flare/vent meters are required at one or more of your
facilities, you must report the amount of gas flared and vented at each
of those facilities separately from those facilities that do not require
meters and separately from other facilities with meters.
(4) If flare/vent meters are not required at your facility:
(i) You may report the gas flared and vented on a lease or unit
basis. Gas flared and vented from multiple facilities on a single lease
or unit may be reported together.
(ii) If you choose to install meters, you may report the gas volume
flared and vented according to the method specified in paragraph (b)(3)
of this section.
(c) You must prepare and maintain records detailing gas flaring, gas
venting, and liquid hydrocarbon burning for each facility for 6 years.
(1) You must maintain these records on the facility for at least the
first 2 years and have them available for inspection by BSEE
representatives.
(2) After 2 years, you must maintain the records, allow BSEE
representatives to inspect the records upon request and provide copies
to the Regional Supervisor upon request, but are not required to keep
them on the facility.

[[Page 223]]

(3) The records must include, at a minimum:
(i) Daily volumes of gas flared, gas vented, and liquid hydrocarbons
burned;
(ii) Number of hours of gas flaring, gas venting, and liquid
hydrocarbon burning, on a daily and monthly cumulative basis;
(iii) A list of the wells contributing to gas flaring, gas venting,
and liquid hydrocarbon burning, along with gas-oil ratio data;
(iv) Reasons for gas flaring, gas venting, and liquid hydrocarbon
burning; and
(v) Documentation of all required approvals.
(d) If your facility is required to have flare/vent meters:
(1) You must maintain the meter recordings for 6 years.
(i) You must keep these recordings on the facility for 2 years and
have them available for inspection by BSEE representatives.
(ii) After 2 years, you must maintain the recordings, allow BSEE
representatives to inspect the recordings upon request and provide
copies to the Regional Supervisor upon request, but are not required to
keep them on the facility.
(iii) These recordings must include the begin times, end times, and
volumes for all flaring and venting incidents.
(2) You must maintain flare/vent meter calibration and maintenance
records on the facility for 2 years.
(e) If your flaring or venting of gas, or burning of liquid
hydrocarbons, required written or oral approval, you must submit
documentation to the Regional Supervisor summarizing the location,
dates, number of hours, and volumes of gas flared, gas vented, and
liquid hydrocarbons burned under the approval.

Sec. 250.1164 What are the requirements for flaring
or venting gas containing H [bdi2]S?

(a) You may not vent gas containing H2S, except for minor
releases during maintenance and repair activities that do not result in
a 15-minute time-weighted average atmosphere concentration of
H2S of 20 ppm or higher anywhere on the platform.
(b) You may flare gas containing H2S only if you meet the
requirements of Sec. Sec. 250.1160, 250.1161, 250.1163, and the
following additional requirements:
(1) For safety or air pollution prevention purposes, the Regional
Supervisor may further restrict the flaring of gas containing
H2S. The Regional Supervisor will use information provided in
the lessee's H2S Contingency Plan (Sec. 250.490(f)),
Exploration Plan, DPP, DOCD submitted to BOEM, and associated documents
to determine the need for restrictions; and
(2) If the Regional Supervisor determines that flaring at a facility
or group of facilities may significantly affect the air quality of an
onshore area, the Regional Supervisor may require you to conduct an air
quality modeling analysis, under 30 CFR 550.303, to determine the
potential effect of facility emissions. The Regional Supervisor may
require monitoring and reporting, or may restrict or prohibit flaring,
under 30 CFR 550.303 and 30 CFR 550.304.
(c) The Regional Supervisor may require you to submit monthly
reports of flared and vented gas containing H2S. Each report
must contain, on a daily basis:
(1) The volume and duration of each flaring and venting occurrence;
(2) H2S concentration in the flared or vented gas; and
(3) The calculated amount of SO2 emitted.

Other Requirements

Sec. 250.1165 What must I do for enhanced recovery operations?

(a) You must promptly initiate enhanced oil and gas recovery
operations for all reservoirs where these operations would result in an
increase in ultimate recovery of oil or gas under sound engineering and
economic principles.
(b) Before initiating enhanced recovery operations, you must submit
a proposed plan to the BSEE Regional Supervisor and receive approval for
pressure maintenance, secondary or tertiary recovery, cycling, and
similar recovery operations intended to increase the ultimate recovery
of oil and gas

[[Page 224]]

from a reservoir. The proposed plan must include, for each project
reservoir, a geologic and engineering overview and any additional
information required by the BSEE Regional Supervisor. You also must
submit Form BOEM-0127 to BOEM along with the supporting data specified
in BOEM regulations, 30 CFR part 550, subpart K.
(c) You must report to Office of Natural Resources Revenue the
volumes of oil, gas, or other substances injected, produced, or produced
for a second time under 30 CFR 1210.102.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36150, June 6, 2016]

Sec. 250.1166 What additional reporting is required for developments
in the Alaska OCS Region?

(a) For any development in the Alaska OCS Region, you must submit an
annual reservoir management report to the Regional Supervisor. The
report must contain information detailing the activities performed
during the previous year and planned for the upcoming year that will:
(1) Provide for the prevention of waste;
(2) Provide for the protection of correlative rights; and
(3) Maximize ultimate recovery of oil and gas.
(b) If your development is jointly regulated by BSEE and the State
of Alaska, BSEE and the Alaska Oil and Gas Conservation Commission will
jointly determine appropriate reporting requirements to minimize or
eliminate duplicate reporting requirements.
(c) [Reserved]

Sec. 250.1167 What information must I submit with forms and for approvals?

You must submit the supporting information listed in the following
table with the form identified in column 1 and for the approvals
required under this subpart identified in columns 2 through 4:

----------------------------------------------------------------------------------------------------------------
Production
WPT BSEE-0126 Gas cap Downhole within 500-ft
(2 copies) production commingling of a unit or
lease line
----------------------------------------------------------------------------------------------------------------
(a) Maps:
(1) Base map with surface, bottomhole, ............... [bcheck] [bcheck] [bcheck]
and completion locations with respect
to the unit or lease line and the
orientation of representative seismic
lines or cross-sections................
(2) Structure maps with penetration [bcheck] [bcheck] [bcheck] [bcheck]
point and subsea depth for each well
penetrating the reservoirs,
highlighting subject wells; reservoir
boundaries; and original and current
fluid levels...........................
(3) Net sand isopach with total net sand ............... [bcheck] [bcheck]
penetrated for each well, identified at
the penetration point..................
(4) Net hydrocarbon isopach with net ............... [bcheck] [bcheck]
feet of pay for each well, identified
at the penetration point...............
(b) Seismic data:
(1) Representative seismic lines, ............... [bcheck] [bcheck] [bcheck]
including strike and dip lines that
confirm the structure; indicate
polarity...............................
(2) Amplitude extraction of seismic ............... [bcheck] [bcheck] [bcheck]
horizon, if applicable.................
(c) Logs:
(1) Well log sections with tops and [bcheck] [bcheck] [bcheck] [bcheck]
bottoms of the reservoir(s) and
proposed or existing perforations......
(2) Structural cross-sections showing ............... [bcheck] [bcheck] *
the subject well and nearby wells......
(d) Engineering data:
(1) Estimated recoverable reserves for ............... [dagger] [dagger] [bcheck]
each well completion in the reservoir;
total recoverable reserves for each
reservoir; method of calculation;
reservoir parameters used in volumetric
and decline curve analysis.............
(2) Well schematics showing current and ............... [bcheck] [bcheck] [bcheck]
proposed conditions....................
(3) The drive mechanism of each ............... [bcheck] [bcheck] [bcheck]
reservoir..............................
(4) Pressure data, by date, and whether ............... [bcheck] [bcheck]
they are estimated or measured.........

[[Page 225]]

(5) Production data and decline curve ............... [bcheck] [bcheck]
analysis indicative of the reservoir
performance............................
(6) Reservoir simulation with the ............... * * *
reservoir parameters used, history
matches, and prediction runs (include
proposed development scenario).........
(e) General information:
(1) Detailed economic analysis.......... ............... * *
(2) Reservoir name and whether or not it ............... [bcheck] [bcheck] [bcheck]
is competitive as defined under Sec.
250.105................................
(3) Operator name, lessee name(s), ............... [bcheck] [bcheck] [bcheck]
block, lease number, royalty rate, and
unit number (if applicable) of all
relevant leases........................
(4) Geologic overview of project........ ............... [bcheck] [bcheck] [bcheck]
(5) Explanation of why the proposed ............... [bcheck] [bcheck] [bcheck]
completion scenario will maximize
ultimate recovery......................
(6) List of all wells in subject ............... [bcheck] [bcheck] [bcheck]
reservoirs that have ever produced or
been used for injection................
----------------------------------------------------------------------------------------------------------------
[bcheck] Required.
[dagger] Each Gas Cap Production request and Downhole Commingling request must include the estimated recoverable
reserves for (1) the case where your proposed production scenario is approved, and (2) the case where your
proposed production scenario is denied.
* Additional items the Regional Supervisor may request.
Note: All maps must be at a standard scale and show lease and unit lines. The Regional Supervisor may waive
submittal of some of the required data on a case-by-case basis.

(f) Depending on the type of approval requested, you must submit the
appropriate payment of the service fee(s) listed in Sec. 250.125,
according to the instructions in Sec. 250.126.

Subpart L_Oil and Gas Production Measurement, Surface Commingling, and
Security

Sec. 250.1200 Question index table.

The table in this section lists questions concerning Oil and Gas
Production Measurement, Surface Commingling, and Security.

------------------------------------------------------------------------
Frequently asked questions CFR citation
------------------------------------------------------------------------
1. What are the requirements for measuring liquid Sec. 250.1202(a)
hydrocarbons?
2. What are the requirements for liquid Sec. 250.1202(b)
hydrocarbon royalty meters?
3. What are the requirements for run tickets? Sec. 250.1202(c)
4. What are the requirements for liquid Sec. 250.1202(d)
hydrocarbon royalty meter provings?
5. What are the requirements for calibrating a Sec. 250.1202(e)
master meter used in royalty meter provings?
6. What are the requirements for calibrating Sec. 250.1202(f)
mechanical-displacement provers and tank provers?
7. What correction factors must a lessee use when Sec. 250.1202(g)
proving meters with a mechanical displacement
prover, tank prover, or master meter?
8. What are the requirements for establishing and Sec. 250.1202(h)
applying operating meter factors for liquid
hydrocarbons?
9. Under what circumstances does a liquid Sec. 250.1202(i)
hydrocarbon royalty meter need to be taken out of
service, and what must a lessee do?
10. How must a lessee correct gross liquid Sec. 250.1202(j)
hydrocarbon volumes to standard conditions?
11. What are the requirements for liquid Sec. 250.1202(k)
hydrocarbon allocation meters?
12. What are the requirements for royalty and Sec. 250.1202(l)
inventory tank facilities?
13. To which meters do BSEE requirements for gas Sec. 250.1203(a)
measurement apply?
14. What are the requirements for measuring gas? Sec. 250.1203(b)
15. What are the requirements for gas meter Sec. 250.1203(c)
calibrations?
16. What must a lessee do if a gas meter is out of Sec. 250.1203(d)
calibration or malfunctioning?
17. What are the requirements when natural gas Sec. 250.1203(e)
from a Federal lease is transferred to a gas
plant before royalty determination?
18. What are the requirements for measuring gas Sec. 250.1203(f)
lost or used on a lease?
19. What are the requirements for the surface Sec. 250.1204(a)
commingling of production?
20. What are the requirements for a periodic well Sec. 250.1204(b)
test used for allocation?
21. What are the requirements for site security? Sec. 250.1205(a)
22. What are the requirements for using seals? Sec. 250.1205(b)
------------------------------------------------------------------------

[[Page 226]]

Sec. 250.1201 Definitions.

Terms not defined in this section have the meanings given in the
applicable chapter of the API MPMS, which is incorporated by reference
in Sec. 250.198. Terms used in Subpart L have the following meaning:
Allocation meter--a meter used to determine the portion of
hydrocarbons attributable to one or more platforms, leases, units, or
wells, in relation to the total production from a royalty or allocation
measurement point.
API MPMS--the American Petroleum Institute's Manual of Petroleum
Measurement Standards, chapters 1, 20, and 21.
British Thermal Unit (Btu)--the amount of heat needed to raise the
temperature of one pound of water from 59.5 degrees Fahrenheit (59.5
[deg]F) to 60.5 degrees Fahrenheit (60.5 [deg]F) at standard pressure
base (14.73 pounds per square inch absolute (psia)).
Compositional Analysis--separating mixtures into identifiable
components expressed in mole percent.
Force majeure event--an event beyond your control such as war, act
of terrorism, crime, or act of nature which prevents you from operating
the wells and meters on your OCS facility.
Gas lost--gas that is neither sold nor used on the lease or unit nor
used internally by the producer.
Gas processing plant--an installation that uses any process designed
to remove elements or compounds (hydrocarbon and non-hydrocarbon) from
gas, including absorption, adsorption, or refrigeration. Processing does
not include treatment operations, including those necessary to put gas
into marketable conditions such as natural pressure reduction,
mechanical separation, heating, cooling, dehydration, desulphurization,
and compression. The changing of pressures or temperatures in a
reservoir is not processing.
Gas processing plant statement--a monthly statement showing the
volume and quality of the inlet or field gas stream and the plant
products recovered during the period, volume of plant fuel, flare and
shrinkage, and the allocation of these volumes to the sources of the
inlet stream.
Gas royalty meter malfunction--an error in any component of the gas
measurement system which exceeds contractual tolerances.
Gas volume statement--a monthly statement showing gas measurement
data, including the volume (Mcf) and quality (Btu) of natural gas which
flowed through a meter.
Inventory tank--a tank in which liquid hydrocarbons are stored prior
to royalty measurement. The measured volumes are used in the allocation
process.
Liquid hydrocarbons (free liquids)--hydrocarbons which exist in
liquid form at standard conditions after passing through separating
facilities.
Malfunction factor--a liquid hydrocarbon royalty meter factor that
differs from the previous meter factor by an amount greater than 0.0025.
Natural gas--a highly compressible, highly expandable mixture of
hydrocarbons which occurs naturally in a gaseous form and passes a meter
in vapor phase.
Operating meter--a royalty or allocation meter that is used for gas
or liquid hydrocarbon measurement for any period during a calibration
cycle.
Pipeline (retrograde) condensate--liquid hydrocarbons which drop out
of the separated gas stream at any point in a pipeline during
transmission to shore.
Pressure base--the pressure at which gas volumes and quality are
reported. The standard pressure base is 14.73 psia.
Prove--to determine (as in meter proving) the relationship between
the volume passing through a meter at one set of conditions and the
indicated volume at those same conditions.
Royalty meter--a meter approved for the purpose of determining the
volume of gas, oil, or other components removed, saved, or sold from a
Federal lease.
Royalty tank--an approved tank in which liquid hydrocarbons are
measured and upon which royalty volumes are based.
Run ticket--the invoice for liquid hydrocarbons measured at a
royalty point.
Sales meter--a meter at which custody transfer takes place (not
necessarily a royalty meter).
Seal--a device or approved method used to prevent tampering with
royalty measurement components.

[[Page 227]]

Standard conditions--atmospheric pressure of 14.73 pounds per square
inch absolute (psia) and 60 [deg]F.
Surface commingling--the surface mixing of production from two or
more leases and/or unit participating areas prior to royalty
measurement.
Temperature base--the temperature at which gas and liquid
hydrocarbon volumes and quality are reported. The standard temperature
base is 60 [deg]F.
Verification/Calibration--testing and correcting, if necessary, a
measuring device to ensure compliance with industry accepted,
manufacturer's recommended, or regulatory required standard of accuracy.
You or your--the lessee or the operator or other lessees'
representative engaged in operations in the Outer Continental Shelf
(OCS).

Sec. 250.1202 Liquid hydrocarbon measurement.

(a) What are the requirements for measuring liquid hydrocarbons? You
must:
(1) Submit a written application to, and obtain approval from, the
Regional Supervisor before commencing liquid hydrocarbon production, or
making any changes to the previously-approved measurement and/or
allocation procedures. Your application (which may also include any
relevant gas measurement and surface commingling requests) must be
accompanied by payment of the service fee listed in Sec. 250.125. The
service fees are divided into two levels based on complexity as shown in
the following table.

------------------------------------------------------------------------
Application type Actions
------------------------------------------------------------------------
(i) Simple applications, Applications to temporarily reroute
production (for a duration not to exceed
six months); Production tests prior to
pipeline construction; Departures related
to meter proving, well testing, or
sampling frequency.
(ii) Complex applications, Creation of new facility measurement
points (FMPs); Association of leases or
units with existing FMPs; Inclusion of
production from additional structures;
Meter updates which add buy-back gas
meters or pigging meters; Other
applications which request deviations
from the approved allocation procedures.
------------------------------------------------------------------------

(2) Use measurement equipment and procedures that will accurately
measure the liquid hydrocarbons produced from a lease or unit to comply
with the following additional API MPMS industry standards or API RP:
(i) API MPMS, Chapter 4, Section 8 (incorporated by reference as
specified in Sec. 250.198);
(ii) API MPMS, Chapter 5, Section 6 (incorporated by reference as
specified in Sec. 250.198);
(iii) API MPMS, Chapter 5, Section 8 (incorporated by reference as
specified in Sec. 250.198);
(iv) API MPMS, Chapter 11, Section 1 (incorporated by reference as
specified in Sec. 250.198);
(v) API MPMS Chapter 12, Section 2, Part 3 (incorporated by
reference as specified in Sec. 250.198);
(vi) API MPMS Chapter 12, Section 2, Part 4 (incorporated by
reference as specified in Sec. 250.198);
(vii) API MPMS, Chapter 21, Section 2 (incorporated by reference as
specified in Sec. 250.198);
(viii) API MPMS, Chapter 21, Addendum to Section 2 (incorporated by
reference as specified in Sec. 250.198);
(ix) API RP 86 (incorporated by reference as specified in Sec.
250.198);
(3) Use procedures and correction factors according to the
applicable chapters of the API MPMS or RP as incorporated by reference
in 30 CFR 250.198, including the following additional editions:
(i) API MPMS, Chapter 4, Section 8 (incorporated by reference as
specified in Sec. 250.198);
(ii) API MPMS, Chapter 5, Section 6 (incorporated by reference as
specified in Sec. 250.198);
(iii) API MPMS, Chapter 5, Section 8 (incorporated by reference as
specified in Sec. 250.198);
(iv) API MPMS Chapter 11, Section 1 (incorporated by reference as
specified in Sec. 250.198);
(v) API MPMS Chapter 12, Section 2, Part 3 (incorporated by
reference as specified in Sec. 250.198);

[[Page 228]]

(vi) API MPMS Chapter 12, Section 2, Part 4 (incorporated by
reference as specified in Sec. 250.198);
(vii) API RP 86 (incorporated by reference as specified in Sec.
250.198); when obtaining net standard volume and associated measurement
parameters; and
(4) When requested by the Regional Supervisor, provide the pipeline
(retrograde) condensate volumes as allocated to the individual leases or
units.
(b) What are the requirements for liquid hydrocarbon royalty meters?
You must:
(1) Ensure that the royalty meter facilities include the following
approved components (or other BSEE-approved components) which must be
compatible with their connected systems:
(i) A meter equipped with a nonreset totalizer;
(ii) A calibrated mechanical displacement (pipe) prover, master
meter, or tank prover;
(iii) A proportional-to-flow sampling device pulsed by the meter
output;
(iv) A temperature measurement or temperature compensation device;
and
(v) A sediment and water monitor with a probe located upstream of
the divert valve.
(2) Ensure that the royalty meter facilities accomplish the
following:
(i) Prevent flow reversal through the meter;
(ii) Protect meters subjected to pressure pulsations or surges;
(iii) Prevent the meter from being subjected to shock pressures
greater than the maximum working pressure; and
(iv) Prevent meter bypassing.
(3) Maintain royalty meter facilities to ensure the following:
(i) Meters operate within the gravity range specified by the
manufacturer;
(ii) Meters operate within the manufacturer's specifications for
maximum and minimum flow rate for linear accuracy; and
(iii) Meters are reproven when changes in metering conditions affect
the meters' performance such as changes in pressure, temperature,
density (water content), viscosity, pressure, and flow rate.
(4) Ensure that sampling devices conform to the following:
(i) The sampling point is in the flowstream immediately upstream or
downstream of the meter or divert valve in accordance with the API MPMS
(as incorporated by reference in Sec. 250.198);
(ii) The sample container is vapor-tight and includes a power mixing
device to allow complete mixing of the sample before removal from the
container; and
(iii) The sample probe is in the center half of the pipe diameter in
a vertical run and is located at least three pipe diameters downstream
of any pipe fitting within a region of turbulent flow. The sample probe
can be located in a horizontal pipe if adequate stream conditioning such
as power mixers or static mixers are installed upstream of the probe
according to the manufacturer's instructions.
(c) What are the requirements for run tickets? You must:
(1) For royalty meters, ensure that the run tickets clearly identify
all observed data, all correction factors not included in the meter
factor, and the net standard volume.
(2) For royalty tanks, ensure that the run tickets clearly identify
all observed data, all applicable correction factors, on/off seal
numbers, and the net standard volume.
(3) Pull a run ticket at the beginning of the month and immediately
after establishing the monthly meter factor or a malfunction meter
factor.
(4) Send all run tickets for royalty meters and tanks to the
Regional Supervisor within 15 days after the end of the month;
(d) What are the requirements for liquid hydrocarbon royalty meter
provings? You must:
(1) Permit BSEE representatives to witness provings;
(2) Ensure that the integrity of the prover calibration is traceable
to test measures certified by the National Institute of Standards and
Technology;
(3) Prove each operating royalty meter to determine the meter factor
monthly, but the time between meter factor determinations must not
exceed 42 days. When a force majeure event precludes the required
monthly meter proving, meters must be proved within 15 days after being
returned to service. The meters must be proved monthly thereafter, but
the time between meter

[[Page 229]]

factor determinations must not exceed 42 days;
(4) Obtain approval from the Regional Supervisor before proving on a
schedule other than monthly; and
(5) Submit copies of all meter proving reports for royalty meters to
the Regional Supervisor monthly within 15 days after the end of the
month.
(e) What are the requirements for calibrating a master meter used in
royalty meter provings? You must:
(1) Calibrate the master meter to obtain a master meter factor
before using it to determine operating meter factors;
(2) Use a fluid of similar gravity, viscosity, temperature, and flow
rate as the liquid hydrocarbons that flow through the operating meter to
calibrate the master meter;
(3) Calibrate the master meter monthly, but the time between
calibrations must not exceed 42 days;
(4) Calibrate the master meter by recording runs until the results
of two consecutive runs (if a tank prover is used) or five out of six
consecutive runs (if a mechanical-displacement prover is used) produce
meter factor differences of no greater than 0.0002. Lessees must use the
average of the two (or the five) runs that produced acceptable results
to compute the master meter factor;
(5) Install the master meter upstream of any back-pressure or
reverse flow check valves associated with the operating meter. However,
the master meter may be installed either upstream or downstream of the
operating meter; and
(6) Keep a copy of the master meter calibration report at your field
location for 2 years.
(f) What are the requirements for calibrating mechanical-
displacement provers and tank provers? You must:
(1) Calibrate mechanical-displacement provers and tank provers at
least once every 5 years according to the API MPMS as incorporated by
reference in 30 CFR 250.198, including the following additional
editions:
(i) API MPMS, Chapter 4, Section 8 (incorporated by reference as
specified in Sec. 250.198);
(ii) API MPMS Chapter 12, Section 2, Part 4 (incorporated by
reference as specified in Sec. 250.198);
(2) Submit a copy of each calibration report to the Regional
Supervisor within 15 days after the calibration.
(g) What correction factors must I use when proving meters with a
mechanical-displacement prover, tank prover, or master meter? Calculate
the following correction factors using the API MPMS as referenced in 30
CFR 250.198, including the following additional editions:
(1) API MPMS, Chapter 4, Section 8 (incorporated by reference as
specified in Sec. 250.198);
(2) API MPMS Chapter 11, Section 1 (incorporated by reference as
specified in Sec. 250.198);
(3) API MPMS Chapter 12, Section 2, Part 3 (incorporated by
reference as specified in Sec. 250.198);
(4) API MPMS Chapter 12, Section 2, Part 4 (incorporated by
reference as specified in Sec. 250.198);
(h) What are the requirements for establishing and applying
operating meter factors for liquid hydrocarbons? (1) If you use a
mechanical-displacement prover, you must record proof runs until five
out of six consecutive runs produce a difference between individual runs
of no greater than .05 percent. You must use the average of the five
accepted runs to compute the meter factor.
(2) If you use a master meter, you must record proof runs until
three consecutive runs produce a total meter factor difference of no
greater than 0.0005. The flow rate through the meters during the proving
must be within 10 percent of the rate at which the line meter will
operate. The final meter factor is determined by averaging the meter
factors of the three runs;
(3) If you use a tank prover, you must record proof runs until two
consecutive runs produce a meter factor difference of no greater than
.0005. The final meter factor is determined by averaging the meter
factors of the two runs; and
(4) You must apply operating meter factors forward starting with the
date of the proving.
(i) Under what circumstances does a liquid hydrocarbon royalty meter
need to be taken out of service, and what must I do? (1) If the
difference between the meter factor and the previous factor exceeds
0.0025 it is a malfunction factor, and you must:

[[Page 230]]

(i) Remove the meter from service and inspect it for damage or wear;
(ii) Adjust or repair the meter, and reprove it;
(iii) Apply the average of the malfunction factor and the previous
factor to the production measured through the meter between the date of
the previous factor and the date of the malfunction factor; and
(iv) Indicate that a meter malfunction occurred and show all
appropriate remarks regarding subsequent repairs or adjustments on the
proving report.
(2) If a meter fails to register production, you must:
(i) Remove the meter from service, repair and reprove it;
(ii) Apply the previous meter factor to the production run between
the date of that factor and the date of the failure; and
(iii) Estimate and report unregistered production on the run ticket.
(3) If the results of a royalty meter proving exceed the run
tolerance criteria and all measures excluding the adjustment or repair
of the meter cannot bring results within tolerance, you must:
(i) Establish a factor using proving results made before any
adjustment or repair of the meter; and
(ii) Treat the established factor like a malfunction factor (see
paragraph (i)(1) of this section).
(j) How must I correct gross liquid hydrocarbon volumes to standard
conditions? To correct gross liquid hydrocarbon volumes to standard
conditions, you must:
(1) Include Cpl factors in the meter factor calculation or list and
apply them on the appropriate run ticket.
(2) List Ctl factors on the appropriate run ticket when the meter is
not automatically temperature compensated.
(k) What are the requirements for liquid hydrocarbon allocation
meters? For liquid hydrocarbon allocation meters you must:
(1) Take samples continuously proportional to flow or daily (use the
procedure in the applicable chapter of the API MPMS as incorporated by
reference in Sec. 250.198;
(2) For turbine meters, take the sample proportional to the flow
only;
(3) Prove operating allocation meters monthly if they measure 50 or
more barrels per day per meter the previous month. When a force majeure
event precludes the required monthly meter proving, meters must be
proved within 15 days after being returned to service. The meters must
be proved monthly thereafter; or
(4) Prove operating allocation meters quarterly if they measure less
than 50 barrels per day per meter the previous month. When a force
majeure event precludes the required quarterly meter proving, meters
must be proved within 15 days after being returned to service. The
meters must be proved quarterly thereafter;
(5) Keep a copy of the proving reports at the field location for 2
years;
(6) Adjust and reprove the meter if the meter factor differs from
the previous meter factor by more than 2 percent and less than 7
percent;
(7) For turbine meters, remove from service, inspect and reprove the
meter if the factor differs from the previous meter factor by more than
2 percent and less than 7 percent;
(8) Repair and reprove, or replace and prove the meter if the meter
factor differs from the previous meter factor by 7 percent or more; and
(9) Permit BSEE representatives to witness provings.
(l) What are the requirements for royalty and inventory tank
facilities? You must:
(1) Equip each royalty and inventory tank with a vapor-tight thief
hatch, a vent-line valve, and a fill line designed to minimize free fall
and splashing;
(2) For royalty tanks, submit a complete set of calibration charts
(tank tables) to the Regional Supervisor before using the tanks for
royalty measurement;
(3) For inventory tanks, retain the calibration charts for as long
as the tanks are in use and submit them to the Regional Supervisor upon
request; and
(4) Obtain the volume and other measurement parameters by using
corrections factors and procedures in the API MPMS as incorporated by
reference in 30 CFR 250.198, including: API

[[Page 231]]

MPMS Chapter 11, Section 1 (incorporated by reference as specified in
Sec. 250.198).

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 18921, Mar. 29, 2012]

Sec. 250.1203 Gas measurement.

(a) To which meters do BSEE requirements for gas measurement apply?
BSEE requirements for gas measurements apply to all OCS gas royalty and
allocation meters.
(b) What are the requirements for measuring gas? You must:
(1) Submit a written application to, and obtain approval from, the
Regional Supervisor before commencing gas production, or making any
changes to the previously-approved measurement and/or allocation
procedures. Your application (which may also include any relevant liquid
hydrocarbon measurement and surface commingling requests) must be
accompanied by payment of the service fee listed in Sec. 250.125. The
service fees are divided into two levels based on complexity, see table
in Sec. 250.1202(a)(1).
(2) Design, install, use, maintain, and test measurement equipment
and procedures to ensure accurate and verifiable measurement. You must
follow the recommendations in API MPMS or RP and AGA as incorporated by
reference in 30 CFR 250.198, including the following additional
editions:
(i) API RP 86 (incorporated by reference as specified in Sec.
250.198);
(ii) AGA Report No. 7 (incorporated by reference as specified in
Sec. 250.198);
(iii) AGA Report No. 9 (incorporated by reference as specified in
Sec. 250.198);
(iv) AGA Report No. 10 (incorporated by reference as specified in
Sec. 250.198);
(3) Ensure that the measurement components demonstrate consistent
levels of accuracy throughout the system.
(4) Equip the meter with a chart or electronic data recorder. If an
electronic data recorder is used, you must follow the recommendations in
API MPMS.
(5) Take proportional-to-flow or spot samples upstream or downstream
of the meter at least once every 6 months.
(6) When requested by the Regional Supervisor, provide available
information on the gas quality.
(7) Ensure that standard conditions for reporting gross heating
value (Btu) are at a base temperature of 60 [deg]F and at a base
pressure of 14.73 psia and reflect the same degree of water saturation
as in the gas volume.
(8) When requested by the Regional Supervisor, submit copies of gas
volume statements for each requested gas meter. Show whether gas volumes
and gross Btu heating values are reported at saturated or unsaturated
conditions; and
(9) When requested by the Regional Supervisor, provide volume and
quality statements on dispositions other than those on the gas volume
statement.
(c) What are the requirements for gas meter calibrations? You must:
(1) Verify/calibrate operating meters monthly, but do not exceed 42
days between verifications/calibrations. When a force majeure event
precludes the required monthly meter verification/calibration, meters
must be verified/calibrated within 15 days after being returned to
service. The meters must be verified/calibrated monthly thereafter, but
do not exceed 42 days between meter verifications/calibrations;
(2) Calibrate each meter by using the manufacturer's specifications;
(3) Conduct calibrations as close as possible to the average hourly
rate of flow since the last calibration;
(4) Retain calibration reports at the field location for 2 years,
and send the reports to the Regional Supervisor upon request; and
(5) Permit BSEE representatives to witness calibrations.
(d) What must I do if a gas meter is out of calibration or
malfunctioning? If a gas meter is out of calibration or malfunctioning,
you must:
(1) If the readings are greater than the contractual tolerances,
adjust the meter to function properly or remove it from service and
replace it.
(2) Correct the volumes to the last acceptable calibration as
follows:
(i) If the duration of the error can be determined, calculate the
volume adjustment for that period.
(ii) If the duration of the error cannot be determined, apply the
volume adjustment to one-half of the time elapsed since the last
calibration or 21 days, whichever is less.

[[Page 232]]

(e) What are the requirements when natural gas from a Federal lease
on the OCS is transferred to a gas plant before royalty determination?
If natural gas from a Federal lease on the OCS is transferred to a gas
plant before royalty determination:
(1) You must provide the following to the Regional Supervisor upon
request:
(i) A copy of the monthly gas processing plant allocation statement;
and
(ii) Gross heating values of the inlet and residue streams when not
reported on the gas plant statement.
(2) You must permit BSEE to inspect the measurement and sampling
equipment of natural gas processing plants that process Federal
production.
(f) What are the requirements for measuring gas lost or used on a
lease? (1) You must either measure or estimate the volume of gas lost or
used on a lease.
(2) If you measure the volume, document the measurement equipment
used and include the volume measured.
(3) If you estimate the volume, document the estimating method, the
data used, and the volumes estimated.
(4) You must keep the documentation, including the volume data,
easily obtainable for inspection at the field location for at least 2
years, and must retain the documentation at a location of your choosing
for at least 7 years after the documentation is generated, subject to
all other document retention and production requirements in 30 U.S.C.
1713 and 30 CFR part 1212.
(5) Upon the request of the Regional Supervisor, you must provide
copies of the records.

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 18922, Mar. 29, 2012]

Sec. 250.1204 Surface commingling.

(a) What are the requirements for the surface commingling of
production? You must:
(1) Submit a written application to, and obtain approval from, the
Regional Supervisor before commencing the commingling of production or
making any changes to the previously approved commingling procedures.
Your application (which may also include any relevant liquid hydrocarbon
and gas measurement requests) must be accompanied by payment of the
service fee listed in Sec. 250.125. The service fees are divided into
two levels based on complexity, see table in Sec. 250.1202(a)(1).
(2) Upon the request of the Regional Supervisor, lessees who deliver
State lease production into a Federal commingling system must provide
volumetric or fractional analysis data on the State lease production
through the designated system operator.
(b) What are the requirements for a periodic well test used for
allocation? You must:
(1) Conduct a well test at least once every 60 days unless the
Regional Supervisor approves a different frequency. When a force majeure
event precludes the required well test within the prescribed 60 day
period (or other frequency approved by the Regional Supervisor), wells
must be tested within 15 days after being returned to production.
Thereafter, well tests must be conducted at least once every 60 days (or
other frequency approved by the Regional Supervisor);
(2) Follow the well test procedures in 30 CFR part 250, subpart K;
and
(3) Retain the well test data at the field location for 2 years.

Sec. 250.1205 Site security.

(a) What are the requirements for site security? You must:
(1) Protect Federal production against production loss or theft;
(2) Post a sign at each royalty or inventory tank which is used in
the royalty determination process. The sign must contain the name of the
facility operator, the size of the tank, and the tank number;
(3) Not bypass BSEE-approved liquid hydrocarbon royalty meters and
tanks; and
(4) Report the following to the Regional Supervisor as soon as
possible, but no later than the next business day after discovery:
(i) Theft or mishandling of production;
(ii) Tampering or bypassing any component of the royalty measurement
facility; and
(iii) Falsifying production measurements.
(b) What are the requirements for using seals? You must:

[[Page 233]]

(1) Seal the following components of liquid hydrocarbon royalty
meter installations to ensure that tampering cannot occur without
destroying the seal:
(i) Meter component connections from the base of the meter up to and
including the register;
(ii) Sampling systems including packing device, fittings, sight
glass, and container lid;
(iii) Temperature and gravity compensation device components;
(iv) All valves on lines leaving a royalty or inventory storage
tank, including load-out line valves, drain-line valves, and connection-
line valves between royalty and non-royalty tanks; and
(v) Any additional components required by the Regional Supervisor.
(2) Seal all bypass valves of gas royalty and allocation meters.
(3) Number and track the seals and keep the records at the field
location for at least 2 years; and
(4) Make the records of seals available for BSEE inspection.

Subpart M_Unitization

Sec. 250.1300 What is the purpose of this subpart?

This subpart explains how Outer Continental Shelf (OCS) leases are
unitized. If you are an OCS lessee, use the regulations in this subpart
for both competitive reservoir and unitization situations. The purpose
of joint development and unitization is to:
(a) Conserve natural resources;
(b) Prevent waste; and/or
(c) Protect correlative rights, including Federal royalty interests.

Sec. 250.1301 What are the requirements for unitization?

(a) Voluntary unitization. You and other OCS lessees may ask the
Regional Supervisor to approve a request for voluntary unitization. The
Regional Supervisor may approve the request for voluntary unitization if
unitized operations:
(1) Promote and expedite exploration and development; or
(2) Prevent waste, conserve natural resources, or protect
correlative rights, including Federal royalty interests, of a reasonably
delineated and productive reservoir.
(b) Compulsory unitization. The Regional Supervisor may require you
and other lessees to unitize operations of a reasonably delineated and
productive reservoir if unitized operations are necessary to:
(1) Prevent waste;
(2) Conserve natural resources; or
(3) Protect correlative rights, including Federal royalty interests.
(c) Unit area. The area that a unit includes is the minimum number
of leases that will allow the lessees to minimize the number of
platforms, facility installations, and wells necessary for efficient
exploration, development, and production of mineral deposits, oil and
gas reservoirs, or potential hydrocarbon accumulations common to two or
more leases. A unit may include whole leases or portions of leases.
(d) Unit agreement. You, the other lessees, and the unit operator
must enter into a unit agreement. The unit agreement must: allocate
benefits to unitized leases, designate a unit operator, and specify the
effective date of the unit agreement. The unit agreement must terminate
when: the unit no longer produces unitized substances, and the unit
operator no longer conducts drilling or well-workover operations (Sec.
250.180) under the unit agreement, unless the Regional Supervisor orders
or approves a suspension of production under Sec. 250.170.
(e) Unit operating agreement. The unit operator and the owners of
working interests in the unitized leases must enter into a unit
operating agreement. The unit operating agreement must describe how all
the unit participants will apportion all costs and liabilities incurred
maintaining or conducting operations. When a unit involves one or more
net-profit-share leases, the unit operating agreement must describe how
to attribute costs and credits to the net-profit-share lease(s), and
this part of the agreement must be approved by the Regional Supervisor.
Otherwise, you must provide a copy of the unit operating agreement to
the Regional Supervisor, but the Regional Supervisor does not need to
approve the unit operating agreement.

[[Page 234]]

(f) Extension of a lease covered by unit operations. If your unit
agreement expires or terminates, or the unit area adjusts so that no
part of your lease remains within the unit boundaries, your lease
expires unless:
(1) Its initial term has not expired;
(2) You conduct drilling, production, or well-reworking operations
on your lease consistent with applicable regulations; or
(3) BSEE orders or approves a suspension of production or operations
for your lease.
(g) Unit operations. If your lease, or any part of your lease, is
subject to a unit agreement, the entire lease continues for the term
provided in the lease, and as long thereafter as any portion of your
lease remains part of the unit area, and as long as operations continue
the unit in effect.
(1) If you drill, produce or perform well-workover operations on a
lease within a unit, each lease, or part of a lease, in the unit will
remain active in accordance with the unit agreement. Following a
discovery, if your unit ceases drilling activities for a reasonable time
period between the delineation of one or more reservoirs and the
initiation of actual development drilling or production operations and
that time period would extend beyond your lease's primary term or any
extension under Sec. 250.180, the unit operator must request and obtain
BSEE approval of a suspension of production under Sec. 250.170 in order
to keep the unit from terminating.
(2) When a lease in a unit agreement is beyond the primary term and
the lease or unit is not producing, the lease will expire unless:
(i) You conduct a continuous drilling or well reworking program
designed to develop or restore the lease or unit production; or
(ii) BSEE orders or approves a suspension of operations under Sec.
250.170.

Sec. 250.1302 What if I have a competitive reservoir on a lease?

(a) The Regional Supervisor may require you to conduct development
and production operations in a competitive reservoir under either a
joint Competitive Reservoir Development Program submitted to BSEE or a
unitization agreement. A competitive reservoir has one or more producing
or producible well completions on each of two or more leases, or
portions of leases, with different lease operating interests. For
purposes of this paragraph, a producible well completion is a well which
is capable of production and which is shut in at the well head or at the
surface but not necessarily connected to production facilities and from
which the operator plans future production.
(b) You may request that the Regional Supervisor make a preliminary
determination whether a reservoir is competitive. When you receive the
preliminary determination, you have 30 days (or longer if the Regional
Supervisor allows additional time) to concur or to submit an objection
with supporting evidence if you do not concur. The Regional Supervisor
will make a final determination and notify you and the other lessees.
(c) If you conduct drilling or production operations in a reservoir
determined competitive by the BSEE Regional Supervisor, you and the
other affected lessees must submit for approval a joint Competitive
Reservoir Development Program. You must submit the joint Competitive
Reservoir Development Program within 90 days after the Regional
Supervisor makes a final determination that the reservoir is
competitive. The joint Competitive Reservoir Development Program must
provide for the development and/or production of the reservoir. You may
submit supplemental Competitive Reservoir Development Programs for the
Regional Supervisor's approval.
(d) If you and the other affected lessees cannot reach an agreement
on a joint Competitive Reservoir Development Program, submitted to BSEE
within the approved period of time, each lessee must submit a separate
Competitive Reservoir Development Program to the Regional Supervisor.
The Regional Supervisor will hold a hearing to resolve differences in
the separate Competitive Reservoir Development Programs. If the
differences in the separate programs are not resolved at the hearing and
the Regional Supervisor determines that unitization is

[[Page 235]]

necessary under Sec. 250.1301(b), BSEE will initiate unitization under
Sec. 250.1304.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36150, June 6, 2016]

Sec. 250.1303 How do I apply for voluntary unitization?

(a) You must file a request for a voluntary unit with the Regional
Supervisor. Your request must include:
(1) A draft of the proposed unit agreement;
(2) A proposed initial plan of operation;
(3) Supporting geological, geophysical, and engineering data; and
(4) Other information that may be necessary to show that the
unitization proposal meets the criteria of Sec. 250.1300.
(b) The unit agreement must comply with the requirements of this
part. BSEE will maintain and provide a model unit agreement for you to
follow. If BSEE revises the model, BSEE will publish the revised model
in the Federal Register. If you vary your unit agreement from the model
agreement, you must obtain the approval of the Regional Supervisor.
(c) After the Regional Supervisor accepts your unitization proposal,
you, the other lessees, and the unit operator must sign and file copies
of the unit agreement, the unit operating agreement, and the initial
plan of operation with the Regional Supervisor for approval.
(d) You must pay the service fee listed in Sec. 250.125 of this
part with your request for a voluntary unitization proposal or the
expansion of a previously approved voluntary unit to include additional
acreage. Additionally, you must pay the service fee listed in Sec.
250.125 with your request for unitization revision.

Sec. 250.1304 How will BSEE require unitization?

(a) If the Regional Supervisor determines that unitization of
operations within a proposed unit area is necessary to prevent waste,
conserve natural resources of the OCS, or protect correlative rights,
including Federal royalty interests, the Regional Supervisor may require
unitization.
(b) If you ask BSEE to require unitization, you must file a request
with the Regional Supervisor. You must include a proposed unit agreement
as described in Sec. Sec. 250.1301(d) and 250.1303(b); a proposed unit
operating agreement; a proposed initial plan of operation; supporting
geological, geophysical, and engineering data; and any other information
that may be necessary to show that unitization meets the criteria of
Sec. 250.1300. The proposed unit agreement must include a counterpart
executed by each lessee seeking compulsory unitization. Lessees who seek
compulsory unitization must simultaneously serve on the nonconsenting
lessees copies of:
(1) The request;
(2) The proposed unit agreement with executed counterparts;
(3) The proposed unit operating agreement; and
(4) The proposed initial plan of operation.
(c) If the Regional Supervisor initiates compulsory unitization,
BSEE will serve all lessees of the proposed unit area with a proposed
unitization plan and a statement of reasons for the proposed
unitization.
(d) The Regional Supervisor will not require unitization until BSEE
provides all lessees of the proposed unit area written notice and an
opportunity for a hearing. If you want BSEE to hold a hearing, you must
request it within 30 days after you receive written notice from the
Regional Supervisor or after you are served with a request for
compulsory unitization from another lessee.
(e) BSEE will not hold a hearing under this paragraph until at least
30 days after BSEE provides written notice of the hearing date to all
parties owning interests that would be made subject to the unit
agreement. The Regional Supervisor must give all lessees of the proposed
unit area an opportunity to submit views orally and in writing and to
question both those seeking and those opposing compulsory unitization.
Adjudicatory procedures are not required. The Regional Supervisor will
make a decision based upon a record of the hearing, including any
written information made a part of the record. The Regional Supervisor
will arrange for a court reporter to make a verbatim transcript. The
party seeking

[[Page 236]]

compulsory unitization must pay for the court reporter and pay for and
provide to the Regional Supervisor within 10 days after the hearing
three copies of the verbatim transcript.
(f) The Regional Supervisor will issue an order that requires or
rejects compulsory unitization. That order must include a statement of
reasons for the action taken and identify those parts of the record
which form the basis of the decision. Any adversely affected party may
appeal the final order of the Regional Supervisor under 30 CFR part 290.

Subpart N_Outer Continental Shelf Civil Penalties

Outer Continental Shelf Lands Act Civil Penalties

Sec. 250.1400 How does BSEE begin the civil penalty process?

This subpart explains BSEEs civil penalty procedures whenever a
lessee, operator or other person engaged in oil, gas, sulphur or other
minerals operations in the OCS has a violation. Whenever BSEE
determines, on the basis of available evidence, that a violation
occurred and a civil penalty review is appropriate, it will prepare a
case file. BSEE will appoint a Reviewing Officer.

Sec. 250.1401 [Reserved]

Sec. 250.1402 Definitions.

Terms used in this subpart have the following meaning:
Case file means a BSEE document file containing information and the
record of evidence related to the alleged violation.
Civil penalty means a fine. It is a BSEE regulatory enforcement tool
used in addition to Notices of Incidents of Noncompliance and directed
suspensions of production or other operations.
Reviewing Officer means a BSEE employee assigned to review case
files and assess civil penalties.
Violation means failure to comply with the Outer Continental Shelf
Lands Act (OCSLA) or any other applicable laws, with any regulations
issued under the OCSLA, or with the terms or provisions of leases,
licenses, permits, rights-of-way, or other approvals issued under the
OCSLA.
Violator means a person responsible for a violation.

Sec. 250.1403 What is the maximum civil penalty?

The maximum civil penalty is $43,576 per day per violation.

[83 FR 2540, Jan. 18, 2018]

Sec. 250.1404 Which violations will BSEE review for potential
civil penalties?

BSEE will review each of the following violations for potential
civil penalties:
(a) Violations that you do not correct within the period BSEE
grants;
(b) Violations that BSEE determines may constitute, or constituted,
a threat of serious, irreparable, or immediate harm or damage to life
(including fish and other aquatic life), property, any mineral deposit,
or the marine, coastal, or human environment; or
(c) Violations that cause serious, irreparable, or immediate harm or
damage to life (including fish and other aquatic life), property, any
mineral deposit, or the marine, coastal, or human environment.
(d) Violations of the oil spill financial responsibility
requirements at 30 CFR part 553.

Sec. 250.1405 When is a case file developed?

BSEE will develop a case file during its investigation of the
violation, and forward it to a Reviewing Officer if any of the
conditions in Sec. 250.1404 exist. The Reviewing Officer will review
the case file and determine if a civil penalty is appropriate. The
Reviewing Officer may administer oaths and issue subpoenas requiring
witnesses to attend meetings, submit depositions, or produce evidence.

Sec. 250.1406 When will BSEE notify me and provide penalty information?

[[Page 237]]

(b) Information on the violation(s); and
(c) Instruction on how to obtain a copy of the case file, schedule a
meeting, submit information, or pay the penalty.

Sec. 250.1407 How do I respond to the letter of notification?

You have 30 calendar days after you receive the Reviewing Officer's
letter to either:
(a) Request, in writing, a meeting with the Reviewing Officer;
(b) Submit additional information; or
(c) Pay the proposed civil penalty.

Sec. 250.1408 When will I be notified of the Reviewing Officer's decision?

At the end of the 30 calendar days or after the meeting and
submittal of additional information, the Reviewing Officer will review
the case file, including all information you submitted, and send you a
decision. The decision will include the amount of any final civil
penalty, the basis for the civil penalty, and instructions for paying or
appealing the civil penalty.

Sec. 250.1409 What are my appeal rights?

(a) When you receive the Reviewing Officer's final decision, you
have 60 days to either pay the penalty or file an appeal in accordance
with 30 CFR part 290, subpart A.
(b) If you file an appeal, you must either:
(1) Submit a surety bond in the amount of the penalty to the
appropriate Leasing Office in the Region where the penalty was assessed,
following instructions that the Reviewing Officer will include in the
final decision; or
(2) Notify the appropriate Leasing Office, in the Region where the
penalty was assessed, that you want your lease-specific/area-wide bond
on file to be used as the bond for the penalty amount.
(c) If you choose the alternative in paragraph (b)(2) of this
section, the BOEM Regional Director may require additional security
(i.e., security in excess of your existing bond) to ensure sufficient
coverage during an appeal. In that event, the Regional Director will
require you to post the supplemental bond with the regional office in
the same manner as under 30 CFR 556.53(d) through (f). If the Regional
Director determines the appeal should be covered by a lease-specific
abandonment account then you must establish an account that meets the
requirements of 30 CFR part 556.56.
(d) If you do not either pay the penalty or file a timely appeal,
BSEE will take one or more of the following actions:
(1) We will collect the amount you were assessed, plus interest,
late payment charges, and other fees as provided by law, from the date
you received the Reviewing Officer's final decision until the date we
receive payment;
(2) We may initiate additional enforcement, including, if
appropriate, cancellation of the lease, right-of-way, license, permit,
or approval, or the forfeiture of a bond under this part; or
(3) We may bar you from doing further business with the Federal
Government according to Executive Orders 12549 and 12689, and section
2455 of the Federal Acquisition Streamlining Act of 1994, 31 U.S.C.
6101. The Department of the Interior's regulations implementing these
authorities are found at 43 CFR part 12, subpart D.

Federal Oil and Gas Royalty Management Act Civil Penalties Definitions

Sec. 250.1450 What definitions apply to this subpart?

The terms used in this subpart have the same meaning as in 30 U.S.C.
1702.

Penalties After a Period To Correct

Sec. 250.1451 What may BSEE do if I violate a statute, regulation, order,
or lease term relating to a Federal oil and gas lease?

[[Page 238]]

(b) We will serve the Notice of Noncompliance by registered mail or
personal service using the most current address on file as maintained by
the BOEM Leasing Office in your respective Region.

Sec. 250.1452 What if I correct the violation?

The matter will be closed if you correct all of the violations
identified in the Notice of Noncompliance within 20 days after you
receive the Notice (or within a longer time period specified in the
Notice).

Sec. 250.1453 What if I do not correct the violation?

(a) We may send you a Notice of Civil Penalty if you do not correct
all of the violations identified in the Notice of Noncompliance within
20 days after you receive the Notice of Noncompliance (or within a
longer time period specified in that Notice). The Notice of Civil
Penalty will tell you how much penalty you must pay. The penalty may be
up to $500 per day, beginning with the date of the Notice of
Noncompliance, for each violation identified in the Notice of
Noncompliance for as long as you do not correct the violations.
(b) If you do not correct all of the violations identified in the
Notice of Noncompliance within 40 days after you receive the Notice of
Noncompliance (or 20 days following the expiration of a longer time
period specified in that Notice), we may increase the penalty to up to
$5,000 per day, beginning with the date of the Notice of Noncompliance,
for each violation for as long as you do not correct the violations.

Sec. 250.1454 How may I request a hearing on the record
on a Notice of Noncompliance?

You may request a hearing on the record on a Notice of Noncompliance
by filing a request within 30 days of the date you received the Notice
of Noncompliance with the Hearings Division (Departmental), Office of
Hearings and Appeals, U.S. Department of the Interior, 801 North Quincy
Street, Arlington, Virginia 22203. You may do this regardless of whether
you correct the violations identified in the Notice of Noncompliance.

Sec. 250.1455 Does my request for a hearing on the record
affect the penalties?

(a) If you do not correct the violations identified in the Notice of
Noncompliance, the penalties will continue to accrue even if you request
a hearing on the record.
(b) You may petition the Hearings Division (Departmental) of the
Office of Hearings and Appeals, to stay the accrual of penalties pending
the hearing on the record and a decision by the Administrative Law Judge
under Sec. 250.1472.
(1) You must file your petition within 45 calendar days of receiving
the Notice of Noncompliance.
(2) To stay the accrual of penalties, you must post a bond or other
surety instrument, or demonstrate financial solvency, using the
standards and requirements as prescribed in BOEM's regulations, 30 CFR
part 550, subpart N. The posted amount must cover the unpaid principal
and interest due for the Notice of Noncompliance, plus the amount of any
penalties accrued before the date a stay becomes effective.
(3) The Hearings Division will grant or deny the petition under 43
CFR 4.21(b).

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36150, June 6, 2016]

Sec. 250.1456 May I request a hearing on the record regarding the amount of
a civil penalty if I did not request a hearing on the Notice of Noncompliance?

(a) You may request a hearing on the record to challenge only the
amount of a civil penalty when you receive a Notice of Civil Penalty, if
you did not previously request a hearing on the record under Sec.
250.1454. If you did not request a hearing on the record on the Notice
of Noncompliance under Sec. 250.1454, you may not contest your
underlying liability for civil penalties.
(b) You must file your request within 10 days after you receive the
Notice of Civil Penalty with the Hearings Division (Departmental),
Office of Hearings and Appeals, U.S. Department of the

[[Page 239]]

Interior, 801 North Quincy Street, Arlington, Virginia 22203.

Penalties Without a Period To Correct

Sec. 250.1460 May I be subject to penalties without prior notice
and an opportunity to correct?

The Federal Oil and Gas Royalty Management Act sets out several
specific violations for which penalties accrue without an opportunity to
first correct the violation.
(a) Under 30 U.S.C. 1719(c), you may be subject to penalties of up
to $10,000 per day per violation for each day the violation continues if
you:
(1) Fail or refuse to permit lawful entry, inspection, or audit; or
(2) Knowingly or willfully fail or refuse to notify the Secretary,
within 5 business days after any well begins production on a lease site
or allocated to a lease site, or resumes production in the case of a
well which has been off production for more than 90 days, of the date on
which production has begun or resumed.
(b) Under 30 U.S.C. 1719(d), you may be subject to civil penalties
of up to $25,000 per day for each day each violation continues if you:
(1) Knowingly or willfully prepare, maintain, or submit false,
inaccurate, or misleading reports, notices, affidavits, records, data,
or other written information;
(2) Knowingly or willfully take or remove, transport, use or divert
any oil or gas from any lease site without having valid legal authority
to do so; or
(3) Purchase, accept, sell, transport, or convey to another person,
any oil or gas knowing or having reason to know that such oil or gas was
stolen or unlawfully removed or diverted.

Sec. 250.1461 How will BSEE inform me of violations without
a period to correct?

We will inform you of any violation, without a period to correct, by
issuing a Notice of Noncompliance and Civil Penalty explaining the
violation, how to correct it, and the penalty assessment. We will serve
the Notice of Noncompliance and Civil Penalty by registered mail or
personal service using your address of record as specified under 30 CFR
part 1218, Subpart H.

Sec. 250.1462 How may I request a hearing on the record on
a Notice of Noncompliance regarding violations without a period to correct?

You may request a hearing on the record of a Notice of Noncompliance
regarding violations without a period to correct by filing a request
within 30 days after you receive the Notice of Noncompliance with the
Hearings Division (Departmental), Office of Hearings and Appeals, U.S.
Department of the Interior, 801 North Quincy Street, Arlington, Virginia
22203. You may do this regardless of whether you correct the violations
identified in the Notice of Noncompliance.

Sec. 250.1463 Does my request for a hearing on the record
affect the penalties?

(a) If you do not correct the violations identified in the Notice of
Noncompliance regarding violations without a period to correct, the
penalties will continue to accrue even if you request a hearing on the
record.
(b) You may ask the Hearings Division (Departmental) to stay the
accrual of penalties pending the hearing on the record and a decision by
the Administrative Law Judge under Sec. 250.1472.
(1) You must file your petition within 45 calendar days after you
receive the Notice of Noncompliance.
(2) To stay the accrual of penalties, you must post a bond or other
surety instrument, or demonstrate financial solvency, using the
standards and requirements as prescribed in BOEM's regulations, 30 CFR
part 550, subpart N. The posted amount must cover the unpaid principal
and interest due for the Notice of Noncompliance, plus the amount of any
penalties accrued before the date a stay becomes effective.
(3) The Hearings Division will grant or deny the petition under 43
CFR 4.21(b).

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36150, June 6, 2016]

[[Page 240]]

Sec. 250.1464 May I request a hearing on the record regarding the amount
of a civil penalty if I did not request a hearing
on the Notice of Noncompliance?

(a) You may request a hearing on the record to challenge only the
amount of a civil penalty when you receive a Notice of Civil Penalty
regarding violations without a period to correct, if you did not
previously request a hearing on the record under Sec. 250.1462. If you
did not request a hearing on the record on the Notice of Noncompliance
under Sec. 250.1462, you may not contest your underlying liability for
civil penalties.
(b) You must file your request within 10 days after you receive
Notice of Civil Penalty with the Hearings Division (Departmental),
Office of Hearings and Appeals, U.S. Department of the Interior, 801
North Quincy, Arlington, Virginia 22203.

General Provisions

Sec. 250.1470 How does BSEE decide what the amount of the penalty should be?

We determine the amount of the penalty by considering the severity
of the violations, your history of compliance, and if you are a small
business.

Sec. 250.1471 Does the penalty affect whether I owe interest?

If you do not pay the penalty by the date required under Sec.
250.1475(d), BSEE will assess you late payment interest on the penalty
amount at the same rate interest is assessed under 30 CFR 1218.54.

Sec. 250.1472 How will the Office of Hearings and Appeals
conduct the hearing on the record?

If you request a hearing on the record under Sec. Sec. 250.1454,
250.1456, 250.1462, or 250.1464, the hearing will be conducted by a
Departmental Administrative Law Judge from the Office of Hearings and
Appeals. After the hearing, the Administrative Law Judge will issue a
decision in accordance with the evidence presented and applicable law.

Sec. 250.1473 How may I appeal the Administrative Law Judge's decision?

If you are adversely affected by the Administrative Law Judge's
decision, you may appeal that decision to the Interior Board of Land
Appeals under 43 CFR part 4, subpart E.

Sec. 250.1474 May I seek judicial review of the decision
of the Interior Board of Land Appeals?

Under 30 U.S.C. 1719(j), you may seek judicial review of the
decision of the Interior Board of Land Appeals. A suit for judicial
review in the District Court will be barred unless filed within 90 days
after the final order.

Sec. 250.1475 When must I pay the penalty?

(a) You must pay the amount of the Notice of Civil Penalty issued
under Sec. 250.1453 or Sec. 250.1461, if you do not request a hearing
on the record under Sec. 250.1454, Sec. 250.1456, Sec. 250.1462, or
Sec. 250.1464.
(b) If you request a hearing on the record under Sec. 250.1454,
Sec. 250.1456, Sec. 250.1462, or Sec. 250.1464, but you do not appeal
the determination of the Administrative Law Judge to the Interior Board
of Land Appeals under Sec. 250.1473, you must pay the amount assessed
by the Administrative Law Judge.
(c) If you appeal the determination of the Administrative Law Judge
to the Interior Board of Land Appeals, you must pay the amount assessed
in the IBLA decision.
(d) You must pay the penalty assessed within 40 days after:
(1) You received the Notice of Civil Penalty, if you did not request
a hearing on the record under either Sec. 250.1454, Sec. 250.1456,
Sec. 250.1462, or Sec. 250.1464;
(2) You received an Administrative Law Judge's decision under Sec.
250.1472, if you obtained a stay of the accrual of penalties pending the
hearing on the record under Sec. 250.1455(b) or Sec. 250.1463(b) and
did not appeal the Administrative Law Judge's determination to the IBLA
under Sec. 250.1473;
(3) You received an IBLA decision under Sec. 250.1473 if the IBLA
continued the stay of accrual of penalties pending its decision and you
did not seek judicial review of the IBLA's decision; or
(4) A final non-appealable judgment of a court of competent
jurisdiction is entered, if you sought judicial review

[[Page 241]]

of the IBLA's decision and the Department or the appropriate court
suspended compliance with the IBLA's decision pending the adjudication
of the case.
(e) If you do not pay, that amount is subject to collection under
the provisions of Sec. 250.1477.

Sec. 250.1476 Can BSEE reduce my penalty once it is assessed?

Under 30 U.S.C. 1719(g), the Director or his or her delegate may
compromise or reduce civil penalties assessed under this part.

Sec. 250.1477 How may BSEE collect the penalty?

(a) BSEE may use all available means to collect the penalty
including, but not limited to:
(1) Requiring the lease surety, for amounts owed by lessees, to pay
the penalty;
(2) Deducting the amount of the penalty from any sums the United
States owes to you; and
(3) Using judicial process to compel your payment under 30 U.S.C.
1719(k).
(b) If the Department uses judicial process, or if you seek judicial
review under Sec. 250.1474 and the court upholds assessment of a
penalty, the court shall have jurisdiction to award the amount assessed
plus interest assessed from the date of the expiration of the 90-day
period referred to in Sec. 250.1474. The amount of any penalty, as
finally determined, may be deducted from any sum owing to you by the
United States.

Criminal Penalties

Sec. 250.1480 May the United States criminally prosecute me
for violations under Federal oil and gas leases?

If you commit an act for which a civil penalty is provided at 30
U.S.C. 1719(d) and Sec. 250.1460(b), the United States may pursue
criminal penalties as provided at 30 U.S.C. 1720, in addition to any
authority for prosecution under other statutes.

Subpart O_Well Control and Production Safety Training

Sec. 250.1500 Definitions.

Terms used in this subpart have the following meaning:
Contractor and contract personnel mean anyone, other than an
employee of the lessee, performing well control, deepwater well control,
or production safety duties for the lessee.
Deepwater well control means well control when you are using a
subsea BOP system.
Employee means direct employees of the lessees who are assigned well
control, deepwater well control, or production safety duties.
I or you means the lessee engaged in oil, gas, or sulphur operations
in the Outer Continental Shelf (OCS).
Lessee means a person who has entered into a lease with the United
States to explore for, develop, and produce the leased minerals. The
term lessee also includes an owner of operating rights for that lease
and the BOEM-approved assignee of that lease.
Periodic means occurring or recurring at regular intervals. Each
lessee must specify the intervals for periodic training and periodic
assessment of training needs in their training programs.
Production operations include, but are not limited to, separation,
dehydration, compression, sweetening, and metering operations.
Production safety includes measures, practices, procedures, and
equipment to ensure safe, accident-free, and pollution-free production
operations, as well as installation, repair, testing, maintenance, and
operation of surface and subsurface safety equipment.
Well completion/well workover means those operations following the
drilling of a well that are intended to establish or restore production.
Well-control means methods used to minimize the potential for the
well to flow or kick and to maintain control of the well in the event of
flow or a kick. Well-control applies to drilling, well-completion, well-
workover, abandonment, and well-servicing operations. It includes
measures, practices, procedures and equipment, such as fluid flow

[[Page 242]]

monitoring, to ensure safe and environmentally protective drilling,
completion, abandonment, and workover operations as well as the
installation, repair, maintenance, and operation of surface and subsea
well-control equipment.

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50896, Aug. 22, 2012]

Sec. 250.1501 What is the goal of my training program?

The goal of your training program must be safe and clean OCS
operations. To accomplish this, you must ensure that your employees and
contract personnel engaged in well control, deepwater well control, or
production safety operations understand and can properly perform their
duties.

Sec. 250.1503 What are my general responsibilities for training?

(a) You must establish and implement a training program so that all
of your employees are trained to competently perform their assigned well
control, deepwater well control, and production safety duties. You must
verify that your employees understand and can perform the assigned well
control, deepwater well control, or production safety duties.
(b) If you conduct operations with a subsea BOP stack, your
employees and contract personnel must be trained in deepwater well
control. The trained employees and contract personnel must have a
comprehensive knowledge of deepwater well control equipment, practices,
and theory.
(c) You must have a training plan that specifies the type,
method(s), length, frequency, and content of the training for your
employees. Your training plan must specify the method(s) of verifying
employee understanding and performance. This plan must include at least
the following information:
(1) Procedures for training employees in well control, deepwater
well control, or production safety practices;
(2) Procedures for evaluating the training programs of your
contractors;
(3) Procedures for verifying that all employees and contractor
personnel engaged in well control, deepwater well control, or production
safety operations can perform their assigned duties;
(4) Procedures for assessing the training needs of your employees on
a periodic basis;
(5) Recordkeeping and documentation procedures; and
(6) Internal audit procedures.
(d) Upon request of the District Manager or Regional Supervisor, you
must provide:
(1) Copies of training documentation for personnel involved in well
control, deepwater well control, or production safety operations during
the past 5 years; and
(2) A copy of your training plan.

Sec. 250.1504 May I use alternative training methods?

You may use alternative training methods. These methods may include
computer-based learning, films, or their equivalents. This training
should be reinforced by appropriate demonstrations and ``hands-on''
training. Alternative training methods must be conducted according to,
and meet the objectives of, your training plan.

Sec. 250.1505 Where may I get training for my employees?

You may get training from any source that meets the requirements of
your training plan.

Sec. 250.1506 How often must I train my employees?

You determine the frequency of the training you provide your
employees. You must do all of the following:
(a) Provide periodic training to ensure that employees maintain
understanding of, and competency in, well control, deepwater well
control, or production safety practices;
(b) Establish procedures to verify adequate retention of the
knowledge and skills that employees need to perform their assigned well
control, deepwater well control, or production safety duties; and
(c) Ensure that your contractors' training programs provide for
periodic training and verification of well control, deepwater well
control, or production safety knowledge and skills.

[[Page 243]]

Sec. 250.1507 How will BSEE measure training results?

BSEE may periodically assess your training program, using one or
more of the methods in this section.
(a) Training system audit. BSEE or its authorized representative may
conduct a training system audit at your office. The training system
audit will compare your training program against this subpart. You must
be prepared to explain your overall training program and produce
evidence to support your explanation.
(b) Employee or contract personnel interviews. BSEE or its
authorized representative may conduct interviews at either onshore or
offshore locations to inquire about the types of training that were
provided, when and where this training was conducted, and how effective
the training was.
(c) Employee or contract personnel testing. BSEE or its authorized
representative may conduct testing at either onshore or offshore
locations for the purpose of evaluating an individual's knowledge and
skills in perfecting well control, deepwater well control, and
production safety duties.
(d) Hands-on production safety, simulator, or live well testing.
BSEE or its authorized representative may conduct tests at either
onshore or offshore locations. Tests will be designed to evaluate the
competency of your employees or contract personnel in performing their
assigned well control, deepwater well control, and production safety
duties. You are responsible for the costs associated with this testing,
excluding salary and travel costs for BSEE personnel.

Sec. 250.1508 What must I do when BSEE administers written or oral tests?

BSEE or its authorized representative may test your employees or
contract personnel at your worksite or at an onshore location. You and
your contractors must:
(a) Allow BSEE or its authorized representative to administer
written or oral tests; and
(b) Identify personnel by current position, years of experience in
present position, years of total oil field experience, and employer's
name (e.g., operator, contractor, or sub-contractor company name).

Sec. 250.1509 What must I do when BSEE administers or requires hands-on,
simulator, or other types of testing?

If BSEE or its authorized representative conducts, or requires you
or your contractor to conduct hands-on, simulator, or other types of
testing, you must:
(a) Allow BSEE or its authorized representative to administer or
witness the testing;
(b) Identify personnel by current position, years of experience in
present position, years of total oil field experience, and employer's
name (e.g., operator, contractor, or sub-contractor company name); and
(c) Pay for all costs associated with the testing, excluding salary
and travel costs for BSEE personnel.

Sec. 250.1510 What will BSEE do if my training program does not
comply with this subpart?

If BSEE determines that your training program is not in compliance,
we may initiate one or more of the following enforcement actions:
(a) Issue an Incident of Noncompliance (INC);
(b) Require you to revise and submit to BSEE your training plan to
address identified deficiencies;
(c) Assess civil/criminal penalties; or
(d) Initiate disqualification procedures.

Subpart P_Sulphur Operations

Sec. 250.1600 Performance standard.

Operations to discover, develop, and produce sulphur in the OCS
shall be in accordance with a BOEM-approved Exploration Plan or
Development and Production Plan and shall be conducted in a manner to
protect against harm or damage to life (including fish and other aquatic
life), property, natural resources of the OCS including any mineral
deposits (in areas leased or not leased), the National security or
defense, and the marine, coastal, or human environment.

[[Page 244]]

Sec. 250.1601 Definitions.

Terms used in this subpart shall have the meanings as defined below:
Air line means a tubing string that is used to inject air within a
sulphur producing well to airlift sulphur out of the well.
Bleedwater means a mixture of mine water or booster water and
connate water that is produced by a bleedwell.
Bleedwell means a well drilled into a producing sulphur deposit that
is used to control the mine pressure generated by the injection of mine
water.
Brine means the water containing dissolved salt obtained from a
brine well by circulating water into and out of a cavity in the salt
core of a salt dome.
Brine well means a well drilled through cap rock into the core at a
salt dome for the purpose of producing brine.
Cap rock means the rock formation, a body of limestone, anhydride,
and/or gypsum, overlying a salt dome.
Sulphur deposit means a formation of rock that contains elemental
sulphur.
Sulphur production rate means the number of long tons of sulphur
produced during a certain period of time, usually per day.

Sec. 250.1602 Applicability.

(a) The requirements of this subpart P are applicable to all
exploration, development, and production operations under an OCS sulphur
lease. Sulphur operations include all activities conducted under a lease
for the purpose of discovery or delineation of a sulphur deposit and for
the development and production of elemental sulphur. Sulphur operations
also include activities conducted for related purposes. Activities
conducted for related purposes include, but are not limited to,
production of other minerals, such as salt, for use in the exploration
for or the development and production of sulphur. The lessee must have
obtained the right to produce and/or use these other minerals.
(b) Lessees conducting sulphur operations in the OCS shall comply
with the requirements of the applicable provisions of subparts A, B, C,
I, J, M, N, O, and Q of this part and the applicable provisions of 30
CFR 550 subparts A, B, C, J and N.
(c) Lessees conducting sulphur operations in the OCS are also
required to comply with the requirements in the applicable provisions of
subparts D, E, F, H, K, and L of this part and the applicable provisions
of 30 CFR 550, subpart K, where such provisions specifically are
referenced in this subpart.

Sec. 250.1603 Determination of sulphur deposit.

(a) Upon receipt of a written request from the lessee, the District
Manager will determine whether a sulphur deposit has been defined that
contains sulphur in paying quantities (i.e., sulphur in quantities
sufficient to yield a return in excess of the costs, after completion of
the wells, of producing minerals at the wellheads).
(b) A determination under paragraph (a) of this section shall be
based upon the following:
(1) Core analyses that indicate the presence of a producible sulphur
deposit (including an assay of elemental sulphur);
(2) An estimate of the amount of recoverable sulphur in long tons
over a specified period of time; and
(3) Contour map of the cap rock together with isopach map showing
the extent and estimated thickness of the sulphur deposit.

Sec. 250.1604 General requirements.

Sulphur lessees shall comply with requirements of this section when
conducting well-drilling, well-completion, well-workover, or production
operations.
(a) Equipment movement. The movement of well-drilling, well-
completion, or well-workover rigs and related equipment on and off an
offshore platform, or from one well to another well on the same offshore
platform, including rigging up and rigging down, shall be conducted in a
safe manner.
(b) Hydrogen sulfide (H2S). When a drilling, well-completion, well-
workover, or production operation is being conducted on a well in zones
known to contain H2S or in zones where the presence of
H2S is unknown (as defined in Sec. 250.490 of this part),
the

[[Page 245]]

lessee shall take appropriate precautions to protect life and property,
especially during operations such as dismantling wellhead equipment and
flow lines and circulating the well. The lessee shall also take
appropriate precautions when H2S is generated as a result of
sulphur production operations. The lessee shall comply with the
requirements in Sec. 250.490 of this part as well as the requirements
of this subpart.
(c) Welding and burning practices and procedures. All welding,
burning, and hot-tapping activities involved in drilling, well-
completion, well-workover or production operations shall be conducted
with properly maintained equipment, trained personnel, and appropriate
procedures in order to minimize the danger to life and property
according to the specific requirements in Sec. Sec. 250.109 through
250.113 of this part.
(d) Electrical requirements. All electrical equipment and systems
involved in drilling, well-completion, well-workover, and production
operations shall be designed, installed, equipped, protected, operated,
and maintained so as to minimize the danger to life and property in
accordance with the requirements of Sec. 250.114 of this part.
(e) Structures on fixed OCS platforms. Derricks, cranes, masts,
substructures, and related equipment shall be selected, designed,
installed, used, and maintained so as to be adequate for the potential
loads and conditions of loading that may be encountered during the
operations. Prior to moving equipment such as a well-drilling, well-
completion, or well-workover rig or associated equipment or production
equipment onto a platform, the lessee shall determine the structural
capability of the platform to safely support the equipment and
operations, taking into consideration corrosion protection, platform
age, and previous stresses.
(f) Traveling-block safety device. All drilling units being used for
drilling, well-completion, or well-workover operations that have both a
traveling block and a crown block must be equipped with a safety device
that is designed to prevent the traveling block from striking the crown
block. The device must be checked for proper operation weekly and after
each drill-line slipping operation. The results of the operational check
must be entered in the operations log.

Sec. 250.1605 Drilling requirements.

(a) Sulphur leases. Lessees of OCS sulphur leases shall conduct
drilling operations in accordance with Sec. Sec. 250.1605 through
250.1619 of this subpart and with other requirements of this part, as
appropriate.
(b) Fitness of drilling unit. (1) Drilling units shall be capable of
withstanding the oceanographic and meteorological conditions for the
proposed season and location of operations.
(2) Prior to commencing operation, drilling units shall be made
available for a complete inspection by the District Manager.
(3) The lessee shall provide information and data on the fitness of
the drilling unit to perform the proposed drilling operation. The
information shall be submitted with, or prior to, the submission of Form
BSEE-0123, Application for Permit to Drill (APD), in accordance with
Sec. 250.1617 of this subpart. After a drilling unit has been approved
by a BSEE district office, the information required in this paragraph
need not be resubmitted unless required by the District Manager or there
are changes in the equipment that affect the rated capacity of the unit.
(c) Oceanographic, meteorological, and drilling unit performance
data. Where oceanographic, meteorological, and drilling unit performance
data are not otherwise readily available, lessees shall collect and
report such data upon request to the District Manager. The type of
information to be collected and reported will be determined by the
District Manager in the interests of safety in the conduct of operations
and the structural integrity of the drilling unit.
(d) Foundation requirements. When the lessee fails to provide
sufficient information pursuant to 30 CFR 550.211 through 550.228 and 30
CFR 550.241 through 550.262 to support a determination that the seafloor
is capable of supporting a specific bottom-founded drilling unit under
the site-specific soil and oceanographic conditions, the District
Manager may require that additional

[[Page 246]]

surveys and soil borings be performed and the results submitted for
review and evaluation by the District Manager before approval is granted
for commencing drilling operations.
(e) Tests, surveys, and samples. (1) Lessees shall drill and take
cores and/or run well and mud logs through the objective interval to
determine the presence, quality, and quantity of sulphur and other
minerals (e.g., oil and gas) in the cap rock and the outline of the
commercial sulphur deposit.
(2) Inclinational surveys shall be obtained on all vertical wells at
intervals not exceeding 1,000 feet during the normal course of drilling.
Directional surveys giving both inclination and azimuth shall be
obtained on all directionally drilled wells at intervals not exceeding
500 feet during the normal course of drilling and at intervals not
exceeding 200 feet in all planned angle-change portions of the borehole.
(3) Directional surveys giving both inclination and azimuth shall be
obtained on both vertically and directionally drilled wells at intervals
not exceeding 500 feet prior to or upon setting a string of casing, or
production liner, and at total depth. Composite directional surveys
shall be prepared with the interval shown from the bottom of the
conductor casing. In calculating all surveys, a correction from the true
north to Universal-Transverse-Mercator-Grid-north or Lambert-Grid-north
shall be made after making the magnetic-to-true-north correction. A
composite dipmeter directional survey or a composite measurement while-
drilling directional survey will be acceptable as fulfilling the
applicable requirements of this paragraph.
(4) Wells are classified as vertical if the calculated average of
inclination readings weighted by the respective interval lengths between
readings from surface to drilled depth does not exceed 3 degrees from
the vertical. When the calculated average inclination readings weighted
by the length of the respective interval between readings from the
surface to drilled depth exceeds 3 degrees, the well is classified as
directional.
(5) At the request of a holder of an adjoining lease, the Regional
Supervisor may, for the protection of correlative rights, furnish a copy
of the directional survey to that leaseholder.
(f) Fixed drilling platforms. Applications for installation of fixed
drilling platforms or structures including artificial islands shall be
submitted in accordance with the provisions of subpart I, Platforms and
Structures, of this part. Mobile drilling units that have their jacking
equipment removed or have been otherwise immobilized are classified as
fixed bottom founded drilling platforms.
(g) Crane operations. You must operate a crane installed on fixed
platforms according to Sec. 250.108 of this subpart.
(h) Diesel-engine air intakes. Diesel-engine air intakes must be
equipped with a device to shut down the diesel engine in the event of
runaway. Diesel engines that are continuously attended must be equipped
with either remote-operated manual or automatic-shutdown devices. Diesel
engines that are not continuously attended must be equipped with
automatic shutdown devices.

Sec. 250.1606 Control of wells.

The lessee shall take necessary precautions to keep its wells under
control at all times. Operations shall be conducted in a safe and
workmanlike manner. The lessee shall utilize the best available and
safest drilling technologies and state-of-the-art methods to evaluate
and minimize the potential for a well to flow or kick. The lessee shall
utilize personnel who are trained and competent and shall utilize and
maintain equipment and materials necessary to assure the safety and
protection of personnel, equipment, natural resources, and the
environment.

Sec. 250.1607 Field rules.

When geological and engineering information in a field enables a
District Manager to determine specific operating requirements, field
rules may be established for drilling, well completion, or well workover
on the District Manager's initiative or in response to a request from a
lessee; such rules may modify the specific requirements of this subpart.
After field rules have been established, operations in the field shall
be conducted in accordance with such rules and other requirements

[[Page 247]]

of this subpart. Field rules may be amended or canceled for cause at any
time upon the initiative of the District Manager or upon the request of
a lessee.

Sec. 250.1608 Well casing and cementing.

(a) General requirements. (1) For the purpose of this subpart, the
several casing strings in order of normal installation are:
(i) Drive or structural,
(ii) Conductor,
(iii) Cap rock casing,
(iv) Bobtail cap rock casing (required when the cap rock casing does
not penetrate into the cap rock),
(v) Second cap rock casing (brine wells), and
(vi) Production liner.
(2) The lessee shall case and cement all wells with a sufficient
number of strings of casing cemented in a manner necessary to prevent
release of fluids from any stratum through the wellbore (directly or
indirectly) into the sea, protect freshwater aquifers from
contamination, support unconsolidated sediments, and otherwise provide a
means of control of the formation pressures and fluids. Cement
composition, placement techniques, and waiting time shall be designed
and conducted so that the cement in place behind the bottom 500 feet of
casing or total length of annular cement fill, if less, attains a
minimum compressive strength of 160 pounds per square inch (psi).
(3) The lessee shall install casing designed to withstand the
anticipated stresses imposed by tensile, compressive, and buckling
loads; burst and collapse pressures; thermal effects; and combinations
thereof. Safety factors in the drilling and casing program designs shall
be of sufficient magnitude to provide well control during drilling and
to assure safe operations for the life of the well.
(4) In cases where cement has filled the annular space back to the
mud line, the cement may be washed out or displaced to a depth not
exceeding the depth of the structural casing shoe to facilitate casing
removal upon well abandonment if the District Manager determines that
subsurface protection against damage to freshwater aquifers and against
damage caused by adverse loads, pressures, and fluid flows is not
jeopardized.
(5) If there are indications of inadequate cementing (such as lost
returns, cement channeling, or mechanical failure of equipment), the
lessee shall evaluate the adequacy of the cementing operations by
pressure testing the casing shoe. If the test indicates inadequate
cementing, the lessee shall initiate remedial action as approved by the
District Manager. For cap rock casing, the test for adequacy of
cementing shall be the pressure testing of the annulus between the cap
rock and the conductor casings. The pressure shall not exceed 70 percent
of the burst pressure of the conductor casing or 70 percent of the
collapse pressure of the cap rock casing.
(b) Drive or structural casing. This casing shall be set by driving,
jetting, or drilling to a minimum depth of 100 feet below the mud line
or such other depth, as may be required or approved by the District
Manager, in order to support unconsolidated deposits and to provide hole
stability for initial drilling operations. If this portion of the hole
is drilled, a quantity of cement sufficient to fill the annular space
back to the mud line shall be used.
(c) Conductor and cap rock casing setting and cementing
requirements. (1) Conductor and cap rock casing design and setting
depths shall be based upon relevant engineering and geologic factors
including the presence or absence of hydrocarbons, potential hazards,
and water depths. The proposed casing setting depths may be varied,
subject to District Manager approval, to permit the casing to be set in
a competent formation or through formations determined desirable to be
isolated from the wellbore by casing for safer drilling operations.
However, the conductor casing shall be set immediately prior to drilling
into formations known to contain oil or gas or, if unknown, upon
encountering such formations. Cap rock casing shall be set and cemented
through formations known to contain oil or gas or, if unknown, upon
encountering such formations. Upon encountering unexpected formation
pressures, the lessee shall submit a revised casing

[[Page 248]]

program to the District Manager for approval.
(2) Conductor casing shall be cemented with a quantity of cement
that fills the calculated annular space back to the mud line. Cement
fill shall be verified by the observation of cement returns. In the
event that observation of cement returns is not feasible, additional
quantities of cement shall be used to assure fill to the mud line.
(3) Cap rock casing shall be cemented with a quantity of cement that
fills the calculated annular space to at least 200 feet inside the
conductor casing. When geologic conditions such as near surface
fractures and faulting exist, cap rock casing shall be cemented with a
quantity of cement that fills the calculated annular space to the mud
line, unless otherwise approved by the District Manager. In brine wells,
the second cap rock casing shall be cemented with a quantity of cement
that fills the calculated annular space to at least 200 feet above the
setting depth of the first cap rock casing.
(d) Bobtail cap rock casing setting and cementing requirements. (1)
Bobtail cap rock casing shall be set on or just in cap rock and lapped a
minimum of 100 feet into the previous casing string.
(2) Sufficient cement shall be used to fill the annular space to the
top of the bobtail cap rock casing.
(e) Production liner setting and cementing requirements. (1)
Production liners for sulphur wells and bleedwells shall be set in cap
rock at or above the bottom of the open hole (hole that is open in cap
rock, below the bottom of the cap rock casing) and lapped into the
previous casing string or to the surface. For brine wells, the liner
shall be set in salt and lapped into the previous casing string or to
the surface.
(2) The production liner is not required to be cemented unless the
cap rock contains oil or gas. If the cap rock contains oil or gas,
sufficient cement shall be used to fill the annular space to the top of
the production liner.

Sec. 250.1609 Pressure testing of casing.

(a) Prior to drilling the plug after cementing, all casing strings,
except the drive or structural casing, shall be pressure tested. The
conductor casing shall be tested to at least 200 psi. All casing strings
below the conductor casing shall be tested to 500 psi or 0.22 psi/ft,
whichever is greater. (When oil or gas is not present in the cap rock,
the production liner need not be cemented in place; thus, it would not
be subject to pressure testing.) If the pressure declines more than 10
percent in 30 minutes or if there is another indication of a leak, the
casing shall be recemented, repaired, or an additional casing string run
and the casing tested again. The above procedures shall be repeated
until a satisfactory test is obtained. The time, conditions of testing,
and results of all casing pressure tests shall be recorded in the
driller's report.
(b) After cementing any string of casing other than structural,
drilling shall not be resumed until there has been a time lapse of at
least 8 hours under pressure for the conductor casing string or 12 hours
under pressure for all other casing strings. Cement is considered under
pressure if one or more float valves are shown to be holding the cement
in place or when other means of holding pressure are used.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36151, June 6, 2016]

Sec. 250.1610 Blowout preventer systems and system components.

(a) General. The blowout preventer (BOP) systems and system
components shall be designed, installed, used, maintained, and tested to
assure well control.
(b) BOP stacks. The BOP stacks shall consist of an annular preventer
and the number of ram-type preventers as specified under paragraphs (e)
and (f) of this section. The pipe rams shall be of proper size to fit
the drill pipe in use.
(c) Working pressure. The working-pressure rating of any BOP shall
exceed the surface pressure to which it may be anticipated to be
subjected.
(d) BOP equipment. All BOP systems shall be equipped and provided
with the following:
(1) An accumulator system that provides sufficient capacity to
supply 1.5 times the volume necessary to close and hold closed all BOP
equipment units with a minimum pressure of 200 psi above the precharge
pressure, without assistance from a charging system. Accumulator
regulators supplied by rig

[[Page 249]]

air that do not have a secondary source of pneumatic supply must be
equipped with manual overrides or other devices alternately provided to
ensure capability of hydraulic operations if rig air is lost.
(2) An automatic backup to the accumulator system. The backup system
shall be supplied by a power source independent from the power source to
the primary accumulator system. The automatic backup system shall
possess sufficient capability to close the BOP and hold it closed.
(3) At least one operable remote BOP control station in addition to
the one on the drilling floor. This control station shall be in a
readily accessible location away from the drilling floor.
(4) A drilling spool with side outlets, if side outlets are not
provided in the body of the BOP stack, to provide for separate kill and
choke lines.
(5) A choke line and a kill line each equipped with two full-opening
valves. At least one of the valves on the choke line and one valve on
the kill line shall be remotely controlled, except that a check valve
may be installed on the kill line in lieu of the remotely controlled
valve, provided that two readily accessible manual valves are in place
and the check valve is placed between the manual valve and the pump.
(6) A fill-up line above the uppermost preventer.
(7) A choke manifold designed with consideration of anticipated
pressures to which it may be subjected, method of well control to be
employed, surrounding environment, and corrosiveness, volume, and
abrasiveness of fluids. The choke manifold shall also meet the following
requirements:
(i) Manifold and choke equipment subject to well and/or pump
pressure shall have a rated working pressure at least as great as the
rated working pressure of the ram-type BOP's or as otherwise approved by
the District Manager;
(ii) All components of the choke manifold system shall be protected
from freezing by heating, draining, or filling with proper fluids; and
(iii) When buffer tanks are installed downstream of the choke
assemblies for the purpose of manifolding the bleed lines together,
isolation valves shall be installed on each line.
(8) Valves, pipes, flexible steel hoses, and other fittings upstream
of, and including, the choke manifold with a pressure rating at least as
great as the rated working pressure of the ram-type BOP's unless
otherwise approved by the District Manager.
(9) A wellhead assembly with a rated working pressure that exceeds
the pressure to which it might be subjected.
(10) The following system components:
(i) A kelly cock (an essentially full-opening valve) installed below
the swivel and a similar valve of such design that it can be run through
the BOP stack installed at the bottom of the kelly. A wrench to fit each
valve shall be stored in a location readily accessible to the drilling
crew;
(ii) An inside BOP and an essentially full-opening, drill-string
safety valve in the open position on the rig floor at all times while
drilling operations are being conducted. These valves shall be
maintained on the rig floor to fit all connections that are in the drill
string. A wrench to fit the drill-string safety valve shall be stored in
a location readily accessible to the drilling crew;
(iii) A safety valve available on the rig floor assembled with the
proper connection to fit the casing string being run in the hole; and
(iv) Locking devices installed on the ram-type preventers.
(e) BOP requirements. Prior to drilling below cap rock casing, a BOP
system shall be installed consisting of at least three remote-
controlled, hydraulically operated BOP's including at least one equipped
with pipe rams, one with blind rams, and one annular type.
(f) Tapered drill-string operations. Prior to commencing tapered
drill-string operations, the BOP stack shall be equipped with
conventional and/or variable-bore pipe rams to provide either of the
following:
(1) One set of variable bore rams capable of sealing around both
sizes in the string and one set of blind rams, or
(2) One set of pipe rams capable of sealing around the larger size
string, provided that blind-shear ram capability is present, and
crossover subs to

[[Page 250]]

the larger size pipe are readily available on the rig floor.

Sec. 250.1611 Blowout preventer systems tests, actuations, inspections,
and maintenance.

(a) Prior to conducting high-pressure tests, all BOP systems shall
be tested to a pressure of 200 to 300 psi.
(b) Ram-type BOP's and the choke manifold shall be pressure tested
with water to rated working pressure or as otherwise approved by the
District Manager. Annular type BOP's shall be pressure tested with water
to 70 percent of rated working pressure or as otherwise approved by the
District Manager.
(c) In conjunction with the weekly pressure test of BOP systems
required in paragraph (d) of this section, the choke manifold valves,
upper and lower kelly cocks, and drill-string safety valves shall be
pressure tested to pipe-ram test pressures. Safety valves with proper
casing connections shall be actuated prior to running casing.
(d) BOP system shall be pressure tested as follows:
(1) When installed;
(2) Before drilling out each string of casing or before continuing
operations in cases where cement is not drilled out;
(3) At least once each week, but not exceeding 7 days between
pressure tests, alternating between control stations. If either control
system is not functional, further drilling operations shall be suspended
until that system becomes operable. A period of more than 7 days between
BOP tests is allowed when there is a stuck drill pipe or there are
pressure control operations and remedial efforts are being performed,
provided that the pressure tests are conducted as soon as possible and
before normal operations resume. The date, time, and reason for
postponing pressure testing shall be entered into the driller's report.
Pressure testing shall be performed at intervals to allow each drilling
crew to operate the equipment. The weekly pressure test is not required
for blind and blind-shear rams;
(4) Blind and blind-shear rams shall be actuated at least once every
7 days. Closing pressure on the blind and blind-shear rams greater than
necessary to indicate proper operation of the rams is not required;
(5) Variable bore-pipe rams shall be pressure tested against all
sizes of pipe in use, excluding drill collars and bottomhole tools; and
(6) Following the disconnection or repair of any well-pressure
containment seal in the wellhead/BOP stack assembly. In this situation,
the pressure tests may be limited to the affected component.
(e) All BOP systems shall be inspected and maintained to assure that
the equipment will function properly. The BOP systems shall be visually
inspected at least once each day. The manufacturer's recommended
inspection and maintenance procedures are acceptable as guidelines in
complying with this requirement.
(f) The lessee shall record pressure conditions during BOP tests on
pressure charts, unless otherwise approved by the District Manager. The
test duration for each BOP component tested shall be sufficient to
demonstrate that the component is effectively holding pressure. The
charts shall be certified as correct by the operator's representative at
the facility.
(g) The time, date, and results of all pressure tests, actuations,
inspections, and crew drills of the BOP system and system components
shall be recorded in the driller's report. The BOP tests shall be
documented in accordance with the following:
(1) The documentation shall indicate the sequential order of BOP and
auxiliary equipment testing and the pressure and duration of each test.
As an alternate, the documentation in the driller's report may reference
a BOP test plan that contains the required information and is retained
on file at the facility.
(2) The control station used during the test shall be identified in
the driller's report.
(3) Any problems or irregularities observed during BOP and auxiliary
equipment testing and any actions taken to remedy such problems or
irregularities shall be noted in the driller's report.

[[Page 251]]

(4) Documentation required to be entered in the driller's report may
instead be referenced in the driller's report. All records, including
pressure charts, driller's report, and referenced documents, pertaining
to BOP tests, actuations, and inspections, shall be available for BSEE
review at the facility for the duration of the drilling activity.
Following completion of the drilling activity, all drilling records
shall be retained for a period of 2 years at the facility, at the
lessee's field office nearest the OCS facility, or at another location
conveniently available to the District Manager.

Sec. 250.1612 Well-control drills.

Well-control drills must be conducted for each drilling crew in
accordance with the requirements set forth in Sec. 250.711 or as
approved by the District Manager.

[81 FR 26037, Apr. 29, 2016]

Sec. 250.1613 Diverter systems.

(a) When drilling a conductor or cap rock hole, all drilling units
shall be equipped with a diverter system consisting of a diverter
sealing element, diverter lines, and control systems. The diverter
system shall be designed, installed, and maintained so as to divert
gases, water, mud, and other materials away from the facilities and
personnel.
(b) The diverter system shall be equipped with remote-control valves
in the flow lines that can be operated from at least one remote-control
station in addition to the one on the drilling floor. Any valve used in
a diverter system shall be full opening. No manual or butterfly valves
shall be installed in any part of a diverter system. There shall be a
minimum number of turns in the vent line(s) downstream of the spool
outlet flange, and the radius of curvature of turns shall be as large as
practicable. Flexible hose may be used for diversion lines instead of
rigid pipe if the flexible hose has integral end couplings. The entire
diverter system shall be firmly anchored and supported to prevent
whipping and vibrations. All diverter control equipment and lines shall
be protected from physical damage from thrown and falling objects.
(c) For drilling operations conducted with a surface wellhead
configuration, the following shall apply:
(1) If the diverter system utilizes only one spool outlet, branch
lines shall be installed to provide downwind diversion capability, and
(2) No spool outlet or diverter line internal diameter shall be less
than 10 inches, except that dual spool outlets are acceptable if each
outlet has a minimum internal diameter of 8 inches, and both outlets are
piped to overboard lines and that each line downstream of the changeover
nipple at the spool has a minimum internal diameter of 10 inches.
(d) The diverter sealing element and diverter valves shall be
pressure tested to a minimum of 200 psi when nippled upon conductor
casing. No more than 7 days shall elapse between subsequent pressure
tests. The diverter sealing element, diverter valves, and diverter
control systems (including the remote) shall be actuation tested, and
the diverter lines shall be tested for flow prior to spudding and
thereafter at least once each 24-hour period alternating between control
stations. All test times and results shall be recorded in the driller's
report.

Sec. 250.1614 Mud program.

(a) The quantities, characteristics, use, and testing of drilling
mud and the related drilling procedures shall be designed and
implemented to prevent the loss of well control.
(b) The lessee shall comply with requirements concerning mud
control, mud test and monitoring equipment, mud quantities, and safety
precautions in enclosed mud handling areas as prescribed in Sec. Sec.
250.455 through 250.459 of this part, except that the installation of an
operable degasser in the mud system as required in Sec. 250.456(g) is
not required for sulphur operations.

Sec. 250.1615 Securing of wells.

A downhole-safety device such as a cement plug, bridge plug, or
packer shall be timely installed when drilling operations are
interrupted by events such as those that force evacuation of the
drilling crew, prevent station keeping, or require repairs to major
drilling units or well-control equipment. The

[[Page 252]]

use of blind-shear rams or pipe rams and an inside BOP may be approved
by the District Manager in lieu of the above requirements if cap rock
casing has been set.

Sec. 250.1616 Supervision, surveillance, and training.

(a) The lessee shall provide onsite supervision of drilling
operations at all times.
(b) From the time drilling operations are initiated and until the
well is completed or abandoned, a member of the drilling crew or the
toolpusher shall maintain rig-floor surveillance continuously, unless
the well is secured with BOP's, bridge plugs, packers, or cement plugs.
(c) Lessee and drilling contractor personnel shall be trained and
qualified in accordance with the provisions of subpart O of this part.
Records of specific training that lessee and drilling contractor
personnel have successfully completed, the dates of completion, and the
names and dates of the courses shall be maintained at the drill site.

Sec. 250.1617 Application for permit to drill.

(a) Before drilling a well under a BOEM-approved Exploration Plan,
Development and Production Plan, or Development Operations Coordination
Document, you must file Form BSEE-0123, APD, with the District Manager
for approval. The submission of your APD must be accompanied by payment
of the service fee listed in Sec. 250.125. Before starting operations,
you must receive written approval from the District Manager unless you
received oral approval under Sec. 250.140.
(b) An APD shall include rated capacities of the proposed drilling
unit and of major drilling equipment. After a drilling unit has been
approved for use in a BSEE district, the information need not be
resubmitted unless required by the District Manager or there are changes
in the equipment that affect the rated capacity of the unit.
(c) An APD shall include a fully completed Form BSEE-0123 and the
following:
(1) A plat, drawn to a scale of 2,000 feet to the inch, showing the
surface and subsurface location of the well to be drilled and of all the
wells previously drilled in the vicinity from which information is
available. For development wells on a lease, the wells previously
drilled in the vicinity need not be shown on the plat. Locations shall
be indicated in feet from the nearest block line;
(2) The design criteria considered for the well and for well
control, including the following:
(i) Pore pressure;
(ii) Formation fracture gradients;
(iii) Potential lost circulation zones;
(iv) Mud weights;
(v) Casing setting depths;
(vi) Anticipated surface pressures (which for purposes of this
section are defined as the pressure that can reasonably be expected to
be exerted upon a casing string and its related wellhead equipment). In
the calculation of anticipated surface pressure, the lessee shall take
into account the drilling, completion, and producing conditions. The
lessee shall consider mud densities to be used below various casing
strings, fracture gradients of the exposed formations, casing setting
depths, and cementing intervals, total well depth, formation fluid type,
and other pertinent conditions. Considerations for calculating
anticipated surface pressure may vary for each segment of the well. The
lessee shall include as a part of the statement of anticipated surface
pressure the calculations used to determine this pressure during the
drilling phase and the completion phase, including the anticipated
surface pressure used for production string design; and
(vii) If a shallow hazards site survey is conducted, the lessee
shall submit with or prior to the submittal of the APD, two copies of a
summary report describing the geological and manmade conditions present.
The lessee shall also submit two copies of the site maps and data
records identified in the survey strategy.
(3) A BOP equipment program including the following:
(i) The pressure rating of BOP equipment,
(ii) A schematic drawing of the diverter system to be used (plan and
elevation views) showing spool outlet internal diameter(s); diverter
line

[[Page 253]]

lengths and diameters, burst strengths, and radius of curvature at each
turn; valve type, size, working-pressure rating, and location; the
control instrumentation logic; and the operating procedure to be used by
personnel, and
(iii) A schematic drawing of the BOP stack showing the inside
diameter of the BOP stack and the number of annular, pipe ram, variable-
bore pipe ram, blind ram, and blind-shear ram preventers.
(4) A casing program including the following:
(i) Casing size, weight, grade, type of connection and setting
depth, and
(ii) Casing design safety factors for tension, collapse, and burst
with the assumptions made to arrive at these values.
(5) The drilling prognosis including the following:
(i) Estimated coring intervals,
(ii) Estimated depths to the top of significant marker formations,
and
(iii) Estimated depths at which encounters with fresh water,
sulphur, oil, gas, or abnormally pressured water are expected.
(6) A cementing program including type and amount of cement in cubic
feet to be used for each casing string;
(7) A mud program including the minimum quantities of mud and mud
materials, including weight materials, to be kept at the site;
(8) A directional survey program for directionally drilled wells;
(9) An H2S Contingency Plan, if applicable, and if not
previously submitted; and
(10) Such other information as may be required by the District
Manager.
(d) Public information copies of the APD shall be submitted in
accordance with Sec. 250.186 of this part.

Sec. 250.1618 Application for permit to modify.

(a) You must submit requests for changes in plans, changes in major
drilling equipment, proposals to deepen, sidetrack, complete, workover,
or plug back a well, or engage in similar activities to the District
Manager on Form BSEE-0124, Application for Permit to Modify (APM). The
submission of your APM must be accompanied by payment of the service fee
listed in Sec. 250.125. Before starting operations associated with the
change, you must receive written approval from the District Manager
unless you received oral approval under Sec. 250.140.
(b) The Form BSEE-0124 submittal shall contain a detailed statement
of the proposed work that will materially change from the work described
in the approved APD. Information submitted shall include the present
state of the well, including the production liner and last string of
casing, the well depth and production zone, and the well's capability to
produce. Within 30 days after completion of the work, a subsequent
detailed report of all the work done and the results obtained shall be
submitted.
(c) Public information copies of Form BSEE-0124 shall be submitted
in accordance with Sec. 250.186 of this part.

Sec. 250.1619 Well records.

(a) Complete and accurate records for each well and all well
operations shall be retained for a period of 2 years at the lessee's
field office nearest the OCS facility or at another location
conveniently available to the District Manager. The records shall
contain a description of any significant malfunction or problem; all the
formations penetrated; the content and character of sulphur in each
formation if cored and analyzed; the kind, weight, size, grade, and
setting depth of casing; all well logs and surveys run in the wellbore;
and all other information required by the District Manager in the
interests of resource evaluation, prevention of waste, conservation of
natural resources, protection of correlative rights, safety of
operations, and environmental protection.
(b) When drilling operations are suspended or temporarily prohibited
under the provisions of Sec. 250.170 of this part, the lessee shall,
within 30 days after termination of the suspension or temporary
prohibition or within 30 days after the completion of any activities
related to the suspension or prohibition, transmit to the District
Manager duplicate copies of the records of all activities related to and
conducted during the suspension or temporary prohibition on, or attached
to, Form BSEE-0125, End of Operations Report, or

[[Page 254]]

Form BSEE-0124, Application for Permit to Modify, as appropriate.
(c) Upon request by the District Manager or Regional Supervisor, the
lessee shall furnish the following:
(1) Copies of the records of any of the well operations specified in
paragraph (a) of this section;
(2) Copies of the driller's report at a frequency as determined by
the District Manager. Items to be reported include spud dates, casing
setting depths, cement quantities, casing characteristics, mud weights,
lost returns, and any unusual activities; and
(3) Legible, exact copies of reports on cementing, acidizing,
analyses of cores, testing, or other similar services.
(d) As soon as available, the lessee shall transmit copies of logs
and charts developed by well-logging operations, directional-well
surveys, and core analyses. Composite logs of multiple runs and
directional-well surveys shall be transmitted to the District Manager in
duplicate as soon as available but not later than 30 days after
completion of such operations for each well.
(e) If the District Manager determines that circumstances warrant,
the lessee shall submit any other reports and records of operations in
the manner and form prescribed by the District Manager.

Sec. 250.1620 Well-completion and well-workover requirements.

(a) Lessees shall conduct well-completion and well-workover
operations in sulphur wells, bleedwells, and brine wells in accordance
with Sec. Sec. 250.1620 through 250.1626 of this part and other
provisions of this part as appropriate (see Sec. Sec. 250.501 and
250.601 of this part for the definition of well-completion and well-
workover operations).
(b) Well-completion and well-workover operations shall be conducted
in a manner to protect against harm or damage to life (including fish
and other aquatic life), property, natural resources of the OCS
including any mineral deposits (in areas leased and not leased), the
National security or defense, or the marine, coastal, or human
environment.

Sec. 250.1621 Crew instructions.

Prior to engaging in well-completion or well-workover operations,
crew members shall be instructed in the safety requirements of the
operations to be performed, possible hazards to be encountered, and
general safety considerations to protect personnel, equipment, and the
environment. Date and time of safety meetings shall be recorded and
available for BSEE review.

Sec. 250.1622 Approvals and reporting of well-completion
and well-workover operations.

(a) No well-completion or well-workover operation shall begin until
the lessee receives written approval from the District Manager. Approval
for such operations shall be requested on Form BSEE-0124. Approvals by
the District Manager shall be based upon a determination that the
operations will be conducted in a manner to protect against harm or
damage to life, property, natural resources of the OCS, including any
mineral deposits, the National security or defense, or the marine,
coastal, or human environment.
(b) The following information shall be submitted with Form BSEE-0124
(or with Form BSEE-0123):
(1) A brief description of the well-completion or well-workover
procedures to be followed;
(2) When changes in existing subsurface equipment are proposed, a
schematic drawing showing the well equipment; and
(3) Where the well is in zones known to contain H2S or
zones where the presence of H2S is unknown, a description of
the safety precautions to be implemented.
(c)(1) Within 30 days after completion, Form BSEE-0125, including a
schematic of the tubing and the results of any well tests, shall be
submitted to the District Manager.
(2) Within 30 days after completing the well-workover operation,
except routine operations, Form BSEE-0124 shall be submitted to the
District Manager and shall include the results of any well tests and a
new schematic of the well if any subsurface equipment has been changed.

[[Page 255]]

Sec. 250.1623 Well-control fluids, equipment, and operations.

(a) Well-control fluids, equipment, and operations shall be
designed, utilized, maintained, and/or tested as necessary to control
the well in foreseeable conditions and circumstances, including
subfreezing conditions. The well shall be continuously monitored during
well-completion and well-workover operations and shall not be left
unattended at any time unless the well is shut in and secured;
(b) The following well-control fluid equipment shall be installed,
maintained, and utilized:
(1) A fill-up line above the uppermost BOP,
(2) A well-control fluid-volume measuring device for determining
fluid volumes when filling the hole on trips, and
(3) A recording mud-pit-level indicator to determine mud-pit-volume
gains and losses. This indicator shall include both a visual and an
audible warning device.
(c) When coming out of the hole with drill pipe or a workover
string, the annulus shall be filled with well-control fluid before the
change in fluid level decreases the hydrostatic pressure 75 psi or every
five stands of drill pipe or workover string, whichever gives a lower
decrease in hydrostatic pressure. The number of stands of drill pipe or
workover string and drill collars that may be pulled prior to filling
the hole and the equivalent well-control fluid volume shall be
calculated and posted near the operator's station. A mechanical,
volumetric, or electronic device for measuring the amount of well-
control fluid required to fill the hole shall be utilized.

Sec. 250.1624 Blowout prevention equipment.

(a) The BOP system and system components and related well-control
equipment shall be designed, used, maintained, and tested in a manner
necessary to assure well control in foreseeable conditions and
circumstances, including subfreezing conditions. The working pressure of
the BOP system and system components shall equal or exceed the expected
surface pressure to which they may be subjected.
(b) The minimum BOP stack for well-completion operations or for
well-workover operations with the tree removed shall consist of the
following:
(1) Three remote-controlled, hydraulically operated preventers
including at least one equipped with pipe rams, one with blind rams, and
one annular type.
(2) When a tapered string is used, the minimum BOP stack shall
consist of either of the following:
(i) An annular preventer, one set of variable bore rams capable of
sealing around both sizes in the string, and one set of blind rams; or
(ii) An annular preventer, one set of pipe rams capable of sealing
around the larger size string, a preventer equipped with blind-shear
rams, and a crossover sub to the larger size pipe that shall be readily
available on the rig floor.
(c) The BOP systems for well-completion operations, or for well-
workover operations with the tree removed, shall be equipped with the
following:
(1) An accumulator system that provides sufficient capacity to
supply 1.5 times the volume necessary to close and hold closed all BOP
equipment units with a minimum pressure of 200 psi above the precharge
pressure without assistance from a charging system. After February 14,
1992, accumulator regulators supplied by rig air which do not have a
secondary source of pneumatic supply shall be equipped with manual
overrides or alternately other devices provided to ensure capability of
hydraulic operations if rig air is lost;
(2) An automatic backup to the accumulator system supplied by a
power source independent from the power source to the primary
accumulator system and possessing sufficient capacity to close all BOP's
and hold them closed;
(3) Locking devices for the pipe-ram preventers;
(4) At least one remote BOP-control station and one BOP-control
station on the rig floor; and
(5) A choke line and a kill line each equipped with two full-opening
valves and a choke manifold. One of the choke-line valves and one of the
kill-line valves shall be remotely controlled

[[Page 256]]

except that a check valve may be installed on the kill line in lieu of
the remotely-controlled valve provided that two readily accessible
manual valves are in place, and the check valve is placed between the
manual valve and the pump.
(d) The minimum BOP-stack components for well-workover operations
with the tree in place and performed through the wellhead inside of the
sulphur line using small diameter jointed pipe (usually \3/4\ inch to
1\1/4\ inch) as a work string; i.e., small-tubing operations, shall
consist of the following:
(1) For air line changes, the well shall be killed prior to
beginning operations. The procedures for killing the well shall be
included in the description of well-workover procedures in accordance
with Sec. 250.1622 of this part. Under these circumstances, no BOP
equipment is required.
(2) For other work inside of the sulphur line, a tubing stripper or
annular preventer shall be installed prior to beginning work.
(e) An essentially full-opening, work-string safety valve shall be
maintained on the rig floor at all times during well-completion
operations. A wrench to fit the work-string safety valve shall be
readily available. Proper connections shall be readily available for
inserting a safety valve in the work string.

Sec. 250.1625 Blowout preventer system testing, records, and drills.

(a) Prior to conducting high-pressure tests, all BOP systems shall
be tested to a pressure of 200 to 300 psi.
(b) Ram-type BOP's and the choke manifold shall be pressure tested
with water to a rated working pressure or as otherwise approved by the
District Manager. Annular type BOP's shall be pressure tested with water
to 70 percent of rated working pressure or as otherwise approved by the
District Manager.
(c) In conjunction with the weekly pressure test of BOP systems
required in paragraph (d) of this section, the choke manifold valves,
upper and lower kelly cocks, and drill-string safety valves shall be
pressure tested to pipe-ram test pressures. Safety valves with proper
casing connections shall be actuated prior to running casing.
(d) BOP system shall be pressure tested as follows:
(1) When installed;
(2) Before drilling out each string of casing or before continuing
operations in cases where cement is not drilled out;
(3) At least once each week, but not exceeding 7 days between
pressure tests, alternating between control stations. If either control
system is not functional, further drilling operations shall be suspended
until that system becomes operable. A period of more than 7 days between
BOP tests is allowed when there is a stuck drill pipe or there are
pressure control operations, and remedial efforts are being performed,
provided that the pressure tests are conducted as soon as possible and
before normal operations resume. The time, date, and reason for
postponing pressure testing shall be entered into the driller's report.
Pressure testing shall be performed at intervals to allow each drilling
crew to operate the equipment. The weekly pressure test is not required
for blind and blind-shear rams;
(4) Blind and blind-shear rams shall be actuated at least once every
7 days. Closing pressure on the blind and blind-shear rams greater than
necessary to indicate proper operation of the rams is not required;
(5) Variable bore-pipe rams shall be pressure tested against all
sizes of pipe in use, excluding drill collars and bottomhole tools; and
(6) Following the disconnection or repair of any well-pressure
containment seal in the wellhead/BOP stack assembly, the pressure tests
may be limited to the affected component.
(e) All personnel engaged in well-completion operations shall
participate in a weekly BOP drill to familiarize crew members with
appropriate safety measures.
(f) The lessee shall record pressure conditions during BOP tests on
pressure charts, unless otherwise approved by the District Manager. The
test duration for each BOP component tested shall be sufficient to
demonstrate that the component is effectively holding pressure. The
charts shall be certified

[[Page 257]]

as correct by the operator's representative at the facility.
(g) The time, date, and results of all pressure tests, actuations,
inspections, and crew drills of the BOP system and system components
shall be recorded in the operations log. The BOP tests shall be
documented in accordance with the following:
(1) The documentation shall indicate the sequential order of BOP and
auxiliary equipment testing and the pressure and duration of each test.
As an alternate, the documentation in the operations log may reference a
BOP test plan that contains the required information and is retained on
file at the facility.
(2) The control station used during the test shall be identified in
the operations log.
(3) Any problems or irregularities observed during BOP and auxiliary
equipment testing and any actions taken to remedy such problems or
irregularities shall be noted in the operations log.
(4) Documentation required to be entered in the driller's report may
instead be referenced in the driller's report. All records, including
pressure charts, driller's report, and referenced documents, pertaining
to BOP tests, actuations, and inspections shall be available for BSEE
review at the facility for the duration of the drilling activity.
Following completion of the drilling activity, all drilling records
shall be retained for a period of 2 years at the facility, at the
lessee's field office nearest the OCS facility, or at another location
conveniently available to the District Manager.

Sec. 250.1626 Tubing and wellhead equipment.

(a) No tubing string shall be placed into service or continue to be
used unless such tubing string has the necessary strength and pressure
integrity and is otherwise suitable for its intended use.
(b) Wellhead, tree, and related equipment shall be designed,
installed, tested, used, and maintained so as to achieve and maintain
pressure control.

Sec. 250.1627 Production requirements.

(a) The lessee shall conduct sulphur production operations in
compliance with the approved Development and Production Plan
requirements of Sec. Sec. 250.1627 through 250.1634 of this subpart and
requirements of this part, as appropriate.
(b) Production safety equipment shall be designed, installed, used,
maintained, and tested in a manner to assure the safety of operations
and protection of the human, marine, and coastal environments.

Sec. 250.1628 Design, installation, and operation of production systems.

(a) General. All production facilities shall be designed, installed,
and maintained in a manner that provides for efficiency and safety of
operations and protection of the environment.
(b) Approval of design and installation features for sulphur
production facilities. Prior to installation, the lessee shall submit a
sulphur production system application, in duplicate, to the District
Manager for approval. The application shall include information relative
to the proposed design and installation features. Information concerning
approved design and installation features shall be maintained by the
lessee at the lessee's offshore field office nearest the OCS facility or
at another location conveniently available to the District Manager. All
approvals are subject to field verification. The application shall
include the following:
(1) A schematic flow diagram showing size, capacity, design, working
pressure of separators, storage tanks, compressor pumps, metering
devices, and other sulphur-handling vessels;
(2) A schematic piping diagram showing the size and maximum
allowable working pressures as determined in accordance with API RP 14E,
Recommended Practice for Design and Installation of Offshore Production
Platform Piping Systems (as incorporated by reference in Sec. 250.198);
(3) Electrical system information including a plan of each platform
deck, outlining all hazardous areas classified according to API RP 500,
Recommended Practice for Classification of Locations for Electrical
Installations at Petroleum Facilities Classified as Class I, Division 1
and Division 2, or API RP 505, Recommended Practice for

[[Page 258]]

Classification of Locations for Electrical Installations at Petroleum
Facilities Classified as Class I, Zone 0, Zone 1, and Zone 2 (as
incorporated by reference in Sec. 250.198), and outlining areas in
which potential ignition sources are to be installed;
(4) Certification that the design for the mechanical and electrical
systems to be installed were approved by registered professional
engineers. After these systems are installed, the lessee shall submit a
statement to the District Manager certifying that the new installations
conform to the approved designs of this subpart.
(c) Hydrocarbon handling vessels associated with fuel gas system.
You must protect hydrocarbon handling vessels associated with the fuel
gas system with a basic and ancillary surface safety system. This system
must be designed, analyzed, installed, tested, and maintained in
operating condition in accordance with API RP 14C, Analysis, Design,
Installation, and Testing of Basic Surface Safety Systems for Offshore
Production Platforms (as incorporated by reference in Sec. 250.198). If
processing components are to be utilized, other than those for which
Safety Analysis Checklists are included in API RP 14C, you must use the
analysis technique and documentation specified therein to determine the
effect and requirements of these components upon the safety system.
(d) Approval of safety-systems design and installation features for
fuel gas system. Prior to installation, the lessee shall submit a fuel
gas safety system application, in duplicate, to the District Manager for
approval. The application shall include information relative to the
proposed design and installation features. Information concerning
approved design and installation features shall be maintained by the
lessee at the lessee's offshore field office nearest the OCS facility or
at another location conveniently available to the District Manager. All
approvals are subject to field verification. The application shall
include the following:
(1) A schematic flow diagram showing size, capacity, design, working
pressure of separators, storage tanks, compressor pumps, metering
devices, and other hydrocarbon-handling vessels;
(2) A schematic flow diagram (API RP 14C, Figure E1, as incorporated
by reference in Sec. 250.198) and the related Safety Analysis Function
Evaluation chart (API RP 14C, subsection 4.3c, as incorporated by
reference in Sec. 250.198).
(3) A schematic piping diagram showing the size and maximum
allowable working pressures as determined in accordance with API RP 14E,
Design and Installation of Offshore Production Platform Piping Systems
(as incorporated by reference in Sec. 250.198);
(4) Electrical system information including the following:
(i) A plan of each platform deck, outlining all hazardous areas
classified according to API RP 500, Recommended Practice for
Classification of Locations for Electrical Installations at Petroleum
Facilities Classified as Class I, Division 1 and Division 2, or API RP
505, Recommended Practice for Classification of Locations for Electrical
Installations at Petroleum Facilities Classified as Class I, Zone 0,
Zone 1, and Zone 2 (as incorporated by reference in Sec. 250.198), and
outlining areas in which potential ignition sources are to be installed;
(ii) All significant hydrocarbon sources and a description of the
type of decking, ceiling, walls (e.g., grating or solid), and firewalls;
and
(iii) Elementary electrical schematic of any platform safety
shutdown system with a functional legend.
(5) Certification that the design for the mechanical and electrical
systems to be installed was approved by registered professional
engineers. After these systems are installed, the lessee shall submit a
statement to the District Manager certifying that the new installations
conform to the approved designs of this subpart; and
(6) Design and schematics of the installation and maintenance of all
fire- and gas-detection systems including the following:
(i) Type, location, and number of detection heads;
(ii) Type and kind of alarm, including emergency equipment to be
activated;
(iii) Method used for detection;
(iv) Method and frequency of calibration; and

[[Page 259]]

(v) A functional block diagram of the detection system, including
the electric power supply.

Sec. 250.1629 Additional production and fuel gas system requirements.

(a) General. Lessees shall comply with the following production
safety system requirements (some of which are in addition to those
contained in Sec. 250.1628 of this part).
(b) Design, installation, and operation of additional production
systems, including fuel gas handling safety systems. (1) Pressure and
fired vessels must be designed, fabricated, and code stamped in
accordance with the applicable provisions of sections I, IV, and VIII of
the American Society of Mechanical Engineers (ASME) Boiler and Pressure
Vessel Code (as specified in Sec. 250.198). Pressure and fired vessels
must have maintenance inspection, rating, repair, and alteration
performed in accordance with the applicable provisions of API Pressure
Vessel Inspections Code: In-Service Inspection, Rating, Repair, and
Alteration, API 510 (except Sections 5.8 and 9.5) (as incorporated by
reference in Sec. 250.198).
(i) Pressure safety relief valves shall be designed, installed, and
maintained in accordance with applicable provisions of sections I, IV,
and VIII of the ANSI/ASME Boiler and Pressure Vessel Code (as specified
in Sec. 250.198). The safety relief valves shall conform to the valve-
sizing and pressure-relieving requirements specified in these documents;
however, the safety relief valves shall be set no higher than the
maximum-allowable working pressure of the vessel. All safety relief
valves and vents shall be piped in such a way as to prevent fluid from
striking personnel or ignition sources.
(ii) The lessee shall use pressure recorders to establish the
operating pressure ranges of pressure vessels in order to establish the
pressure-sensor settings. Pressure-recording charts used to determine
operating pressure ranges shall be maintained by the lessee for a period
of 2 years at the lessee's field office nearest the OCS facility or at
another location conveniently available to the District Manager. The
high-pressure sensor shall be set no higher than 15 percent or 5 psi,
whichever is greater, above the highest operating pressure of the
vessel. This setting shall also be set sufficiently below (15 percent or
5 psi, whichever is greater) the safety relief valve's set pressure to
assure that the high-pressure sensor sounds an alarm before the safety
relief valve starts relieving. The low-pressure sensor shall sound an
alarm no lower than 15 percent or 5 psi, whichever is greater, below the
lowest pressure in the operating range.
(2) Engine exhaust. You must equip engine exhausts to comply with
the insulation and personnel protection requirements of API RP 14C,
section 4.2c(4) (as incorporated by reference in Sec. 250.198). Exhaust
piping from diesel engines must be equipped with spark arresters.
(3) Firefighting systems. Firefighting systems must conform to
subsection 5.2, Fire Water Systems, of API RP 14G, Recommended Practice
for Fire Prevention and Control on Open Type Offshore Production
Platforms (as incorporated by reference in Sec. 250.198), and must be
subject to the approval of the District Manager. Additional requirements
must apply as follows:
(i) A firewater system consisting of rigid pipe with firehose
stations shall be installed. The firewater system shall be installed to
provide needed protection, especially in areas where fuel handling
equipment is located.
(ii) Fuel or power for firewater pump drivers shall be available for
at least 30 minutes of run time during platform shut-in time. If
necessary, an alternate fuel or power supply shall be installed to
provide for this pump-operating time unless an alternate firefighting
system has been approved by the District Manager;
(iii) A firefighting system using chemicals may be used in lieu of a
water system if the District Manager determines that the use of a
chemical system provides equivalent fire-protection control; and
(iv) A diagram of the firefighting system showing the location of
all firefighting equipment shall be posted in a prominent place on the
facility or structure.
(4) Fire- and gas-detection system. (i) Fire (flame, heat, or smoke)
sensors

[[Page 260]]

shall be installed in all enclosed classified areas. Gas sensors shall
be installed in all inadequately ventilated, enclosed classified areas.
Adequate ventilation is defined as ventilation that is sufficient to
prevent accumulation of significant quantities of vapor-air mixture in
concentrations over 25 percent of the lower explosive limit. One
approved method of providing adequate ventilation is a change of air
volume each 5 minutes or 1 cubic foot of air-volume flow per minute per
square foot of solid floor area, whichever is greater. Enclosed areas
(e.g., buildings, living quarters, or doghouses) are defined as those
areas confined on more than four of their six possible sides by walls,
floors, or ceilings more restrictive to air flow than grating or fixed
open louvers and of sufficient size to allow entry of personnel. A
classified area is any area classified Class I, Group D, Division 1 or
2, following the guidelines of API RP 500 (as incorporated by reference
in Sec. 250.198), or any area classified Class I, Zone 0, Zone 1, or
Zone 2, following the guidelines of API RP 505 (as incorporated by
reference in Sec. 205.198).
(ii) All detection systems shall be capable of continuous
monitoring. Fire-detection systems and portions of combustible gas-
detection systems related to the higher gas concentration levels shall
be of the manual-reset type. Combustible gas-detection systems related
to the lower gas-concentration level may be of the automatic-reset type.
(iii) A fuel-gas odorant or an automatic gas-detection and alarm
system is required in enclosed, continuously manned areas of the
facility that are provided with fuel gas. Living quarters and doghouses
not containing a gas source and not located in a classified area do not
require a gas detection system.
(iv) The District Manager may require the installation and
maintenance of a gas detector or alarm in any potentially hazardous
area.
(v) Fire- and gas-detection systems must be an approved type,
designed and installed according to API RP 14C, API RP 14G, and either
API RP 14F or API RP 14FZ (the preceding four documents as incorporated
by reference in Sec. 250.198).
(c) General platform operations. Safety devices shall not be
bypassed or blocked out of service unless they are temporarily out of
service for startup, maintenance, or testing procedures. Only the
minimum number of safety devices shall be taken out of service.
Personnel shall monitor the bypassed or blocked out functions until the
safety devices are placed back in service. Any safety device that is
temporarily out of service shall be flagged by the person taking such
device out of service.

Sec. 250.1630 Safety-system testing and records.

(a) Inspection and testing. You must inspect and successfully test
safety system devices at the interval specified below or more frequently
if operating conditions warrant. Testing must be in accordance with API
RP 14C, Appendix D (as incorporated by reference in Sec. 250.198). For
safety system devices other than those listed in API RP 14C, Appendix D,
you must utilize the analysis technique and documentation specified
therein for inspection and testing of these components, and the
following:
(1) Safety relief valves on the natural gas feed system for power
plant operations such as pressure safety valves shall be inspected and
tested for operation at least once every 12 months. These valves shall
be either bench tested or equipped to permit testing with an external
pressure source.
(2) The following safety devices (excluding electronic pressure
transmitters and level sensors) must be inspected and tested at least
once each calendar month, but at no time may more than 6 weeks elapse
between tests:
(i) All pressure safety high or pressure safety low, and
(ii) All level safety high and level safety low controls.
(3) The following electronic pressure transmitters and level sensors
must be inspected and tested at least once every 3 months, but at no
time may more than 120 days elapse between tests:
(i) All PSH or PSL, and
(ii) All LSH and LSL controls.

[[Page 261]]

(4) All pumps for firewater systems shall be inspected and operated
weekly.
(5) All fire- (flame, heat, or smoke) and gas-detection systems
shall be inspected and tested for operation and recalibrated every 3
months provided that testing can be performed in a nondestructive
manner.
(6) Prior to the commencement of production, the lessee shall notify
the District Manager when the lessee is ready to conduct a preproduction
test and inspection of the safety system. The lessee shall also notify
the District Manager upon commencement of production in order that a
complete inspection may be conducted.
(b) Records. The lessee shall maintain records for a period of 2
years for each safety device installed. These records shall be
maintained by the lessee at the lessee's field office nearest the OCS
facility or another location conveniently available to the District
Manager. These records shall be available for BSEE review. The records
shall show the present status and history of each safety device,
including dates and details of installation, removal, inspection,
testing, repairing, adjustments, and reinstallation.

Sec. 250.1631 Safety device training.

Prior to engaging in production operations on a lease and
periodically thereafter, personnel installing, inspecting, testing, and
maintaining safety devices shall be instructed in the safety
requirements of the operations to be performed; possible hazards to be
encountered; and general safety considerations to be taken to protect
personnel, equipment, and the environment. Date and time of safety
meetings shall be recorded and available for BSEE review.

Sec. 250.1632 Production rates.

Each sulphur deposit shall be produced at rates that will provide
economic development and depletion of the deposit in a manner that would
maximize the ultimate recovery of sulphur without resulting in waste
(e.g., an undue reduction in the recovery of oil and gas from an
associated hydrocarbon accumulation).

Sec. 250.1633 Production measurement.

(a) General. Measurement equipment and security procedures shall be
designed, installed, used, maintained, and tested so as to accurately
and completely measure the sulphur produced on a lease for purposes of
royalty determination.
(b) Application and approval. The lessee shall not commence
production of sulphur until the Regional Supervisor has approved the
method of measurement. The request for approval of the method of
measurement shall contain sufficient information to demonstrate to the
satisfaction of the Regional Supervisor that the method of measurement
meets the requirements of paragraph (a) of this section.

Sec. 250.1634 Site security.

(a) All locations where sulphur is produced, measured, or stored
shall be operated and maintained to ensure against the loss or theft of
produced sulphur and to assure accurate and complete measurement of
produced sulphur for royalty purposes.
(b) Evidence of mishandling of produced sulphur from an offshore
lease, or tampering or falsifying any measurement of production for an
offshore lease, shall be reported to the Regional Supervisor as soon as
possible but no later than the next business day after discovery of the
evidence of mishandling.

Subpart Q_Decommissioning Activities

General

Sec. 250.1700 What do the terms ``decommissioning'', ``obstructions'',
and ``facility'' mean?

(a) Decommissioning means:
(1) Ending oil, gas, or sulphur operations; and
(2) Returning the lease or pipeline right-of-way to a condition that
meets the requirements of regulations of BSEE and other agencies that
have jurisdiction over decommissioning activities.
(b) Obstructions mean structures, equipment, or objects that were
used in oil, gas, or sulphur operations or marine growth that, if left
in place, would

[[Page 262]]

hinder other users of the OCS. Obstructions may include, but are not
limited to, shell mounds, wellheads, casing stubs, mud line suspensions,
well protection devices, subsea trees, jumper assemblies, umbilicals,
manifolds, termination skids, production and pipeline risers, platforms,
templates, pilings, pipelines, pipeline valves, and power cables.
(c) Facility means any installation other than a pipeline used for
oil, gas, or sulphur activities that is permanently or temporarily
attached to the seabed on the OCS. Facilities include production and
pipeline risers, templates, pilings, and any other facility or equipment
that constitutes an obstruction such as jumper assemblies, termination
skids, umbilicals, anchors, and mooring lines.

Sec. 250.1701 Who must meet the decommissioning obligations in this subpart?

(a) Lessees and owners of operating rights are jointly and severally
responsible for meeting decommissioning obligations for facilities on
leases, including the obligations related to lease-term pipelines, as
the obligations accrue and until each obligation is met.
(b) All holders of a right-of-way are jointly and severally liable
for meeting decommissioning obligations for facilities on their right-
of-way, including right-of-way pipelines, as the obligations accrue and
until each obligation is met.
(c) In this subpart, the terms ``you'' or ``I'' refer to lessees and
owners of operating rights, as to facilities installed under the
authority of a lease, and to right-of-way holders as to facilities
installed under the authority of a right-of-way.

Sec. 250.1702 When do I accrue decommissioning obligations?

You accrue decommissioning obligations when you do any of the
following:
(a) Drill a well;
(b) Install a platform, pipeline, or other facility;
(c) Create an obstruction to other users of the OCS;
(d) Are or become a lessee or the owner of operating rights of a
lease on which there is a well that has not been permanently plugged
according to this subpart, a platform, a lease term pipeline, or other
facility, or an obstruction;
(e) Are or become the holder of a pipeline right-of-way on which
there is a pipeline, platform, or other facility, or an obstruction; or
(f) Re-enter a well that was previously plugged according to this
subpart.

Sec. 250.1703 What are the general requirements for decommissioning?

When your facilities are no longer useful for operations, you must:
(a) Get approval from the appropriate District Manager before
decommissioning wells and from the Regional Supervisor before
decommissioning platforms and pipelines or other facilities;
(b) Permanently plug all wells. Permanently installed packers and
bridge plugs must comply with API Spec. 11D1 (as incorporated by
reference in Sec. 250.198);
(c) Remove all platforms and other facilities, except as provided in
Sec. Sec. 250.1725(a) and 250.1730.
(d) Decommission all pipelines;
(e) Clear the seafloor of all obstructions created by your lease and
pipeline right-of-way operations;
(f) Follow all applicable requirements of subpart G of this part;
and
(g) Conduct all decommissioning activities in a manner that is safe,
does not unreasonably interfere with other uses of the OCS, and does not
cause undue or serious harm or damage to the human, marine, or coastal
environment.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 26037, Apr. 29 2016]

Sec. 250.1704 What decommissioning applications and reports must I submit
and when must I submit them?

You must submit decommissioning applications, receive approval of
those applications, and submit subsequent reports according to the
requirements and deadlines in the following table.

[[Page 263]]

Decommissioning Applications and Reports Table
----------------------------------------------------------------------------------------------------------------
Decommissioning applications and
reports When to submit Instructions
----------------------------------------------------------------------------------------------------------------
(a) Initial platform removal In the Pacific OCS Region Include information required under Sec.
application [not required in the or Alaska OCS Region, 250.1726.
Gulf of Mexico OCS Region]. submit the application to
the Regional Supervisor
at least 2 years before
production is projected
to cease.
(b) Final removal application for a Before removing a platform Include information required under Sec.
platform or other facility. or other facility in the 250.1727.
Gulf of Mexico OCS
Region, or not more than
2 years after the
submittal of an initial
platform removal
application to the
Pacific OCS Region and
the Alaska OCS Region.
(c) Post-removal report for a Within 30 days after you Include information required under Sec.
platform or other facility. remove a platform or 250.1729.
other facility.
(d) Pipeline decommissioning Before you decommission a Include information required under Sec.
application. pipeline. 250.1751(a) or Sec. 250.1752(a), as
applicable.
(e) Post-pipeline decommissioning Within 30 days after you Include information required under Sec.
report. decommission a pipeline. 250.1753.
(f) Site clearance report for a Within 30 days after you Include information required under Sec.
platform or other facility. complete site clearance 250.1743(b).
verification activities.
(g) Form BSEE-0124, Application for (1) Before you temporarily (i) Include information required under Sec.
Permit to Modify (APM). The abandon or permanently Sec. 250.1712 and 250.1721.
submission of your APM must be plug a well or zone,. (ii) When using a BOP for abandonment
accompanied by payment of the operations, include information required under
service fee listed in Sec. Sec. 250.731.
250.125;.
(2) Before you install a Refer to Sec. 250.1722(a).
subsea protective device,.
(3) Before you remove any Refer to Sec. 250.1723.
casing stub or mud line
suspension equipment and
any subsea protective
device,.
(h) Form BSEE-0125, End of (1) Within 30 days after Include information required under Sec.
Operations Report (EOR);. you complete a protective 250.1722(d).
device trawl test,.
(2) Within 30 days after Include information required under Sec.
you complete site 250.1743(a).
clearance verification
activities,.
----------------------------------------------------------------------------------------------------------------
(i) A certified summary of Within 120 days after Submit to the Regional Supervisor a complete
expenditures for permanently completion of each summary of expenditures actually incurred for
plugging any well, removal of any decommissioning activity each decommissioning activity (including, but
platform or other facility, specified in this not limited to, the use of rigs, vessels,
clearance of any site after wells paragraph. equipment, supplies and materials;
have been plugged or platforms or transportation of any kind; personnel; and
facilities removed, and services). Include in, or attach to, the
decommissioning of pipelines. summary a certified statement by an authorized
representative of your company attesting to
the truth, accuracy and completeness of the
summary. The Regional Supervisor may provide
specific instructions or guidance regarding
how to submit the certified summary.
(j) If requested by the Regional Within a reasonable time The Regional Supervisor will review the summary
Supervisor, additional information as determined by the and may provide specific instructions or
in support of any decommissioning Regional Supervisor. guidance regarding the submission of
activity expenditures included in additional information (including, but not
a summary submitted under limited to, copies of contracts and invoices),
paragraph (i) of this section. if requested, to complete or otherwise support
the summary.
----------------------------------------------------------------------------------------------------------------

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50896, Aug. 22, 2012;
80 FR 75810, Dec. 4, 2015; 81 FR 26037, Apr. 29, 2016; 81 FR 80591, Nov.
16, 2016]

[[Page 264]]

Sec. 250.1705 [Reserved]

Sec. 250.1706 Coiled tubing and snubbing operations.

If you use a BOP for any well abandonment operations, your BOP must
meet the following requirements:
(a) For coiled tubing operations with the production tree in place,
you must meet the following minimum requirements for the BOP system:
(1) BOP system components must be in the following order from the
top down:

------------------------------------------------------------------------
BOP system when
BOP system when expected expected surface BOP system for wells
surface pressures are less pressures are with returns taken
than or equal to 3,500 psi greater than through an outlet on
3,500 psi the BOP stack
------------------------------------------------------------------------
(i) Stripper or annular-type Stripper or Stripper or annular-
well-control component, annular-type type well-control
well-control component.
component,
(ii) Hydraulically-operated Hydraulically- Hydraulically-
blind rams, operated blind operated blind rams.
rams,.
(iii) Hydraulically-operated Hydraulically- Hydraulically-
shear rams, operated shear operated shear rams.
rams,.
(iv) Kill line inlet, Kill line inlet, Kill line inlet.
(v) Hydraulically-operated two- Hydraulically- Hydraulically-
way slip rams, operated two-way operated two-way
slip rams, slip rams.
Hydraulically-
operated pipe rams.
(vi) Hydraulically-operated Hydraulically- A flow tee or cross.
pipe rams, operated pipe Hydraulically-
rams. operated pipe rams.
Hydraulically- Hydraulically-
operated blind- operated blind-shear
shear rams. rams on wells with
These rams surface pressures
should be 3,500
located as close psi. As an option,
to the tree as the pipe rams can be
practical,. placed below the
blind-shear rams.
The blind-shear rams
should be located as
close to the tree as
practical.
------------------------------------------------------------------------

(2) You may use a set of hydraulically-operated combination rams for
the blind rams and shear rams.
(3) You may use a set of hydraulically-operated combination rams for
the hydraulic two-way slip rams and the hydraulically-operated pipe
rams.
(4) You must attach a dual check valve assembly to the coiled tubing
connector at the downhole end of the coiled tubing string for all coiled
tubing well abandonment operations. If you plan to conduct operations
without downhole check valves, you must describe alternate procedures
and equipment in Form BSEE-0124, Application for Permit to Modify, and
have it approved by the BSEE District Manager.
(5) You must have a kill line and a separate choke line. You must
equip each line with two full-opening valves and at least one of the
valves must be remotely controlled. You may use a manual valve instead
of the remotely controlled valve on the kill line if you install a check
valve between the two full-opening manual valves and the pump or
manifold. The valves must have a working pressure rating equal to or
greater than the working pressure rating of the connection to which they
are attached, and you must install them between the well-control stack
and the choke or kill line. For operations with expected surface
pressures greater than 3,500 psi, the kill line must be connected to a
pump or manifold. You must not use the kill line inlet on the BOP stack
for taking fluid returns from the wellbore.
(6) You must have a hydraulic-actuating system that provides
sufficient accumulator capacity to close-open-close each component in
the BOP stack. This cycle must be completed with at least 200 psi above
the pre-charge pressure, without assistance from a charging system.
(7) All connections used in the surface BOP system from the tree to
the uppermost required ram must be flanged, including the connections
between the well-control stack and the first full-opening valve on the
choke line and the kill line.
(b) The minimum BOP system components for well abandonment
operations with the tree in place and performed by moving tubing or
drill pipe in or out of a well under pressure utilizing equipment
specifically designed for that purpose, i.e., snubbing operations, must
include the following:
(1) One set of pipe rams hydraulically operated, and
(2) Two sets of stripper-type pipe rams hydraulically operated with
spacer spool.

[[Page 265]]

(c) An inside BOP or a spring-loaded, back-pressure safety valve,
and an essentially full-opening, work-string safety valve in the open
position must be maintained on the rig floor at all times during well
abandonment operations when the tree is removed or during well
abandonment operations with the tree installed and using small tubing as
the work string. A wrench to fit the work-string safety valve must be
readily available. Proper connections must be readily available for
inserting valves in the work string. The full-opening safety valve is
not required for coiled tubing or snubbing operations.

[77 FR 50897, Aug. 22, 2012, as amended at 81 FR 26037, Apr. 29, 2016]

Sec. Sec. 250.1707-250.1709 [Reserved]

Permanently Plugging Wells

Sec. 250.1710 When must I permanently plug all wells on a lease?

You must permanently plug all wells on a lease within 1 year after
the lease terminates.

Sec. 250.1711 When will BSEE order me to permanently plug a well?

BSEE will order you to permanently plug a well if that well:
(a) Poses a hazard to safety or the environment; or
(b) Is not useful for lease operations and is not capable of oil,
gas, or sulphur production in paying quantities.

Sec. 250.1712 What information must I submit before I permanently plug
a well or zone?

Before you permanently plug a well or zone, you must submit form
BSEE-0124, Application for Permit to Modify, to the appropriate District
Manager and receive approval. A request for approval must contain the
following information:
(a) The reason you are plugging the well (or zone), for completions
with production amounts specified by the Regional Supervisor, along with
substantiating information demonstrating its lack of capacity for
further profitable production of oil, gas, or sulfur;
(b) Recent well test data and pressure data, if available;
(c) Maximum possible surface pressure, and how it was determined;
(d) Type and weight of well-control fluid you will use;
(e) A description of the work;
(f) A current and proposed well schematic and description that
includes:
(1) Well depth;
(2) All perforated intervals that have not been plugged;
(3) Casing and tubing depths and details;
(4) Subsurface equipment;
(5) Estimated tops of cement (and the basis of the estimate) in each
casing annulus;
(6) Plug locations;
(7) Plug types;
(8) Plug lengths;
(9) Properties of mud and cement to be used;
(10) Perforating and casing cutting plans;
(11) Plug testing plans;
(12) Casing removal (including information on explosives, if used);
(13) Proposed casing removal depth; and
(14) Your plans to protect archaeological and sensitive biological
features, including anchor damage during plugging operations, a brief
assessment of the environmental impacts of the plugging operations, and
the procedures and mitigation measures you will take to minimize such
impacts; and
(g) Certification by a Registered Professional Engineer of the well
abandonment design and procedures and that all plugs meet the
requirements in the table in Sec. 250.1715. In addition to the
requirements of Sec. 250.1715, the Registered Professional Engineer
must also certify the design will include two independent barriers, one
of which must be a mechanical barrier, in the center wellbore as
described in Sec. 250.420(b)(3). The Registered Professional Engineer
must be registered in a State of the United States and have sufficient
expertise and experience to perform the certification. You must submit
this certification with your APM (Form BSEE-0124).

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50900, Aug. 22, 2012]

[[Page 266]]

Sec. 250.1713 Must I notify BSEE before I begin well plugging operations?

You must notify the appropriate District Manager at least 48 hours
before beginning operations to permanently plug a well.

Sec. 250.1714 What must I accomplish with well plugs?

You must ensure that all well plugs:
(a) Provide downhole isolation of hydrocarbon and sulphur zones;
(b) Protect freshwater aquifers; and
(c) Prevent migration of formation fluids within the wellbore or to
the seafloor.

Sec. 250.1715 How must I permanently plug a well?

(a) You must permanently plug wells according to the table in this
section. The District Manager may require additional well plugs as
necessary.

Permanent Well Plugging Requirements
----------------------------------------------------------------------------------------------------------------
If you have . . . Then you must use . . .
---------------------------------------------------------------------------------------------------------------
(1) Zones in open hole, Cement plug(s) set from at least 100 feet below the
bottom to 100 feet above the top of oil, gas, and fresh-
water zones to isolate fluids in the strata.
(2) Open hole below casing, (i) A cement plug, set by the displacement method, at
least 100 feet above and below deepest casing shoe;
(ii) A cement retainer with effective back-pressure
control set 50 to 100 feet above the casing shoe, and a
cement plug that extends at least 100 feet below the
casing shoe and at least 50 feet above the retainer; or
(iii) A bridge plug set 50 feet to 100 feet above the
shoe with 50 feet of cement on top of the bridge plug,
for expected or known lost circulation conditions.
(3) A perforated zone that is currently open and (i) A method to squeeze cement to all perforations;
not previously squeezed or isolated, (ii) A cement plug set by the displacement method, at
least 100 feet above to 100 feet below the perforated
interval, or down to a casing plug, whichever is less;
or.
(iii) If the perforated zones are isolated from the hole
below, you may use any of the plugs specified in
paragraphs (a)(3)(iii)(A) through (E) of this section
instead of those specified in paragraphs (a)(3)(i) and
(a)(3)(ii) of this section..
(A) A cement retainer with effective back-pressure
control set 50 to 100 feet above the top of the
perforated interval, and a cement plug that extends at
least 100 feet below the bottom of the perforated
interval with at least 50 feet of cement above the
retainer;
(B) A casing bridge plug set 50 to 100 feet above the top
of the perforated interval and at least 50 feet of
cement on top of the bridge plug;
(C) A cement plug at least 200 feet in length, set by the
displacement method, with the bottom of the plug no more
than 100 feet above the perforated interval;
(D) A through-tubing basket plug set no more than 100
feet above the perforated interval with at least 50 feet
of cement on top of the basket plug; or
(E) A tubing plug set no more than 100 feet above the
perforated interval topped with a sufficient volume of
cement so as to extend at least 100 feet above the
uppermost packer in the wellbore and at least 300 feet
of cement in the casing annulus immediately above the
packer.
(4) A casing stub where the stub end is within the (i) A cement plug set at least 100 feet above and below
casing, the stub end;
(ii) A cement retainer or bridge plug set at least 50 to
100 feet above the stub end with at least 50 feet of
cement on top of the retainer or bridge plug; or
(iii) A cement plug at least 200 feet long with the
bottom of the plug set no more than 100 feet above the
stub end.
(5) A casing stub where the stub end is below the A plug as specified in paragraph (a)(1) or (a)(2) of this
casing, section, as applicable.
(6) An annular space that communicates with open A cement plug at least 200 feet long set in the annular
hole and extends to the mud line, space. For a well completed above the ocean surface, you
must pressure test each casing annulus to verify
isolation.
(7) A subsea well with unsealed annulus, A cutter to sever the casing, and you must set a stub
plug as specified in paragraphs (a)(4) and (a)(5) of
this section.
(8) A well with casing, A cement surface plug at least 150 feet long set in the
smallest casing that extends to the mud line with the
top of the plug no more than 150 feet below the mud
line.
(9) Fluid left in the hole, A fluid in the intervals between the plugs that is dense
enough to exert a hydrostatic pressure that is greater
than the formation pressures in the intervals.
(10) Permafrost areas, (i) A fluid to be left in the hole that has a freezing
point below the temperature of the permafrost, and a
treatment to inhibit corrosion; and

[[Page 267]]

(ii) Cement plugs designed to set before freezing and
have a low heat of hydration.
(11) Removed the barriers required in Sec. Two independent barriers, one of which must be a
250.420(b)(3) for the well to be completed mechanical barrier, in the center wellbore as described
in Sec. 250.420(b)(3) once the well is to be placed in
a permanent or temporary abandonment..
----------------------------------------------------------------------------------------------------------------

(b) You must test the first plug below the surface plug and all
plugs in lost circulation areas that are in open hole. The plug must
pass one of the following tests to verify plug integrity:
(1) A pipe weight of at least 15,000 pounds on the plug; or
(2) A pump pressure of at least 1,000 pounds per square inch. Ensure
that the pressure does not drop more than 10 percent in 15 minutes. The
District Manager may require you to tests other plug(s).

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50900, Aug. 22, 2012;
81 FR 26038, Apr. 29, 2016]

Sec. 250.1716 To what depth must I remove wellheads and casings?

(a) Unless the District Manager approves an alternate depth under
paragraph (b) of this section, you must remove all wellheads and casings
to at least 15 feet below the mud line.
(b) The District Manager may approve an alternate removal depth if:
(1) The wellhead or casing would not become an obstruction to other
users of the seafloor or area, and geotechnical and other information
you provide demonstrate that erosional processes capable of exposing the
obstructions are not expected; or
(2) You determine, and BSEE concurs, that you must use divers, and
the seafloor sediment stability poses safety concerns; or
(3) The water depth is greater than 800 meters (2,624 feet).

Sec. 250.1717 [Reserved]

Temporary Abandoned Wells

Sec. 250.1721 If I temporarily abandon a well that I plan to re-enter,
what must I do?

You may temporarily abandon a well when it is necessary for proper
development and production of a lease. To temporarily abandon a well,
you must do all of the following:
(a) Submit form BSEE-0124, Application for Permit to Modify, and the
applicable information required by Sec. 250.1712 to the appropriate
District Manager and receive approval;
(b) Adhere to the plugging and testing requirements for permanently
plugged wells listed in the table in Sec. 250.1715, except for Sec.
250.1715(a)(8). You do not need to sever the casings, remove the
wellhead, or clear the site;
(c) Set a bridge plug or a cement plug at least 100-feet long at the
base of the deepest casing string, unless the casing string has been
cemented and has not been drilled out. If a cement plug is set, it is
not necessary for the cement plug to extend below the casing shoe into
the open hole;
(d) Set a retrievable or a permanent-type bridge plug or a cement
plug at least 100 feet long in the inner-most casing. The top of the
bridge plug or cement plug must be no more than 1,000 feet below the mud
line. BSEE may consider approving alternate requirements for subsea
wells case-by-case;
(e) Identify and report subsea wellheads, casing stubs, or other
obstructions that extend above the mud line according to U.S. Coast
Guard (USCG) requirements;
(f) Except in water depths greater than 300 feet, protect subsea
wellheads, casing stubs, mud line suspensions, or other obstructions
remaining above the seafloor by using one of the following methods, as
approved by the District Manager or Regional Supervisor:
(1) A caisson designed according to 30 CFR 250, subpart I, and
equipped with aids to navigation;
(2) A jacket designed according to 30 CFR 250, subpart I, and
equipped with aids to navigation; or
(3) A subsea protective device that meets the requirements in Sec.
250.1722.

[[Page 268]]

(g) Submit certification by a Registered Professional Engineer of
the well abandonment design and procedures and that all plugs meet the
requirements of paragraph (b) of this section. In addition to the
requirements of paragraph (b) of this section, the Registered
Professional Engineer must also certify the design will include two
independent barriers, one of which must be a mechanical barrier, in the
center wellbore as described in Sec. 250.420(b)(3). The Registered
Professional Engineer must be registered in a State of the United States
and have sufficient expertise and experience to perform the
certification. You must submit this certification with your APM (Form
BSEE-0124) required by Sec. 250.1712 of this part.

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50900, Aug. 22, 2012;
81 FR 26038, Apr. 29, 2016]

Sec. 250.1722 If I install a subsea protective device, what requirements
must I meet?

If you install a subsea protective device under Sec.
250.1721(f)(3), you must install it in a manner that allows fishing gear
to pass over the obstruction without damage to the obstruction, the
protective device, or the fishing gear.
(a) Use form BSEE-0124, Application for Permit to Modify to request
approval from the appropriate District Manager to install a subsea
protective device.
(b) The protective device may not extend more than 10 feet above the
seafloor (unless BSEE approves otherwise).
(c) You must trawl over the protective device when you install it
(adhere to the requirements at Sec. 250.1741(d) through (h)). If the
trawl does not pass over the protective device or causes damage to it,
you must notify the appropriate District Manager within 5 days and
perform remedial action within 30 days of the trawl;
(d) Within 30 days after you complete the trawling test described in
paragraph (c) of this section, submit a report to the appropriate
District Manager using form BSEE-0124, Application for Permit to Modify
that includes the following:
(1) The date(s) the trawling test was performed and the vessel that
was used;
(2) A plat at an appropriate scale showing the trawl lines;
(3) A description of the trawling operation and the net(s) that were
used;
(4) An estimate by the trawling contractor of the seafloor
penetration depth achieved by the trawl;
(5) A summary of the results of the trawling test including a
discussion of any snags and interruptions, a description of any damage
to the protective covering, the casing stub or mud line suspension
equipment, or the trawl, and a discussion of any snag removals requiring
diver assistance; and
(6) A letter signed by your authorized representative stating that
he/she witnessed the trawling test.
(e) If a temporarily abandoned well is protected by a subsea device
installed in a water depth less than 100 feet, mark the site with a buoy
installed according to the USCG requirements.
(f) Provide annual reports to the Regional Supervisor describing
your plans to either re-enter and complete the well or to permanently
plug the well.
(g) Ensure that all subsea wellheads, casing stubs, mud line
suspensions, or other obstructions in water depths less than 300 feet
remain protected.
(1) To confirm that the subsea protective covering remains properly
installed, either conduct a visual inspection or perform a trawl test at
least annually.
(2) If the inspection reveals that a casing stub or mud line
suspension is no longer properly protected, or if the trawl does not
pass over the subsea protective covering without causing damage to the
covering, the casing stub or mud line suspension equipment, or the
trawl, notify the appropriate District Manager within 5 days, and
perform the necessary remedial work within 30 days of discovery of the
problem.
(3) In your annual report required by paragraph (f) of this section,
include the inspection date, results, and method used and a description
of any remedial work you will perform or have performed.
(h) You may request approval to waive the trawling test required by

[[Page 269]]

paragraph (c) of this section if you plan to use either:
(1) A buoy with automatic tracking capabilities installed and
maintained according to USCG requirements at 33 CFR part 67 (or its
successor); or
(2) A design and installation method that has been proven successful
by trawl testing of previous protective devices of the same design and
installed in areas with similar bottom conditions.

Sec. 250.1723 What must I do when it is no longer necessary to maintain
a well in temporary abandoned status?

If you or BSEE determines that continued maintenance of a well in a
temporary abandoned status is not necessary for the proper development
or production of a lease, you must:
(a) Promptly and permanently plug the well according to Sec.
250.1715;
(b) Remove any casing stub or mud line suspension equipment and any
subsea protective covering. You must submit a request for approval to
perform such work to the appropriate District Manager using form BSEE-
0124, Application for Permit to Modify; and
(c) Clear the well site according to Sec. Sec. 250.1740 through
250.1742.

Removing Platforms and Other Facilities

Sec. 250.1725 When do I have to remove platforms and other facilities?

(a) You must remove all platforms and other facilities within 1 year
after the lease or pipeline right-of-way terminates, unless you receive
approval to maintain the structure to conduct other activities.
Platforms include production platforms, well jackets, single-well
caissons, and pipeline accessory platforms. Other activities include
those supporting OCS oil and gas production and transportation, as well
as other energy-related or marine-related uses (including LNG) for which
adequate financial assurance for decommissioning has been provided to a
Federal agency which has given BSEE a commitment that it has and will
exercise authority to compel the performance of decommissioning within a
time following cessation of the new use acceptable to BSEE. The approval
will specify:
(1) Whether you must continue to maintain any financial assurance
for decommissioning; and
(2) Whether, and under what circumstances, you must perform any
decommissioning not performed by the new facility owner/user.
(b) Before you may remove a platform or other facility, you must
submit a final removal application to the Regional Supervisor for
approval and include the information listed in Sec. 250.1727.
(c) You must remove a platform or other facility according to the
approved application.
(d) You must flush all production risers with seawater before you
remove them.
(e) You must notify the Regional Supervisor at least 48 hours before
you begin the removal operations.

Sec. 250.1726 When must I submit an initial platform removal application
and what must it include?

An initial platform removal application is required only for leases
and pipeline rights-of-way in the Pacific OCS Region or the Alaska OCS
Region. It must include the following information:
(a) Platform or other facility removal procedures, including the
types of vessels and equipment you will use;
(b) Facilities (including pipelines) you plan to remove or leave in
place;
(c) Platform or other facility transportation and disposal plans;
(d) Plans to protect marine life and the environment during
decommissioning operations, including a brief assessment of the
environmental impacts of the operations, and procedures and mitigation
measures that you will take to minimize the impacts; and
(e) A projected decommissioning schedule.

Sec. 250.1727 What information must I include in my final application
to remove a platform or other facility?

You must submit to the Regional Supervisor, a final application for
approval to remove a platform or other facility. Your application must
be accompanied by payment of the service

[[Page 270]]

fee listed in Sec. 250.125. If you are proposing to use explosives,
provide three copies of the application. If you are not proposing to use
explosives, provide two copies of the application. Include the following
information in the final removal application, as applicable:
(a) Identification of the applicant including:
(1) Lease operator/pipeline right-of-way holder;
(2) Address;
(3) Contact person and telephone number; and
(4) Shore base.
(b) Identification of the structure you are removing including:
(1) Platform Name/BSEE Complex ID Number;
(2) Location (lease/right-of-way, area, block, and block
coordinates);
(3) Date installed (year);
(4) Proposed date of removal (Month/Year); and
(5) Water depth.
(c) Description of the structure you are removing including:
(1) Configuration (attach a photograph or a diagram);
(2) Size;
(3) Number of legs/casings/pilings;
(4) Diameter and wall thickness of legs/casings/pilings;
(5) Whether piles are grouted inside or outside;
(6) Brief description of soil composition and condition;
(7) The sizes and weights of the jacket, topsides (by module),
conductors, and pilings; and
(8) The maximum removal lift weight and estimated number of main
lifts to remove the structure.
(d) A description, including anchor pattern, of the vessel(s) you
will use to remove the structure.
(e) Identification of the purpose, including:
(1) Lease expiration/right-of-way relinquishment date; and
(2) Reason for removing the structure.
(f) A description of the removal method, including:
(1) A brief description of the method you will use;
(2) If you are using explosives, the following:
(i) Type of explosives;
(ii) Number and sizes of charges;
(iii) Whether you are using single shot or multiple shots;
(iv) If multiple shots, the sequence and timing of detonations;
(v) Whether you are using a bulk or shaped charge;
(vi) Depth of detonation below the mud line; and
(vii) Whether you are placing the explosives inside or outside of
the pilings;
(3) If you will use divers or acoustic devices to conduct a pre-
removal survey to detect the presence of turtles and marine mammals, a
description of the proposed detection method; and
(4) A statement whether or not you will use transducers to measure
the pressure and impulse of the detonations.
(g) Your plans for transportation and disposal (including as an
artificial reef) or salvage of the removed platform.
(h) If available, the results of any recent biological surveys
conducted in the vicinity of the structure and recent observations of
turtles or marine mammals at the structure site.
(i) Your plans to protect archaeological and sensitive biological
features during removal operations, including a brief assessment of the
environmental impacts of the removal operations and procedures and
mitigation measures you will take to minimize such impacts.
(j) A statement whether or not you will use divers to survey the
area after removal to determine any effects on marine life.

Sec. 250.1728 To what depth must I remove a platform or other facility?

(a) Unless the Regional Supervisor approves an alternate depth under
paragraph (b) of this section, you must remove all platforms and other
facilities (including templates and pilings) to at least 15 feet below
the mud line.
(b) The Regional Supervisor may approve an alternate removal depth
if:
(1) The remaining structure would not become an obstruction to other
users of the seafloor or area, and geotechnical and other information
you provide demonstrate that erosional processes capable of exposing the
obstructions are not expected; or

[[Page 271]]

(2) You determine, and BSEE concurs, that you must use divers and
the seafloor sediment stability poses safety concerns; or
(3) The water depth is greater than 800 meters (2,624 feet).

Sec. 250.1729 After I remove a platform or other facility, what information
must I submit?

Within 30 days after you remove a platform or other facility, you
must submit a written report to the Regional Supervisor that includes
the following:
(a) A summary of the removal operation including the date it was
completed;
(b) A description of any mitigation measures you took; and
(c) A statement signed by your authorized representative that
certifies that the types and amount of explosives you used in removing
the platform or other facility were consistent with those set forth in
the approved removal application.

Sec. 250.1730 When might BSEE approve partial structure removal
or toppling in place?

The Regional Supervisor may grant a departure from the requirement
to remove a platform or other facility by approving partial structure
removal or toppling in place for conversion to an artificial reef if you
meet the following conditions:
(a) The structure becomes part of a State artificial reef program,
and the responsible State agency acquires a permit from the U.S. Army
Corps of Engineers and accepts title and liability for the structure;
and
(b) You satisfy any U.S. Coast Guard (USCG) navigational
requirements for the structure.

Sec. 250.1731 Who is responsible for decommissioning an OCS facility
subject to an Alternate Use RUE?

(a) The holder of an Alternate Use RUE issued under 30 CFR part 585
is responsible for all decommissioning obligations that accrue following
the issuance of the Alternate Use RUE and which pertain to the Alternate
Use RUE. See 30 CFR part 585, subpart J, for additional information
concerning the decommissioning responsibilities of an Alternate Use RUE
grant holder.
(b) The lessee under the lease originally issued under 30 CFR part
556 will remain responsible for decommissioning obligations that accrued
before issuance of the Alternate Use RUE, as well as for decommissioning
obligations that accrue following issuance of the Alternate Use RUE to
the extent associated with continued activities authorized under this
part.
(c) If a lease issued under 30 CFR part 556 is cancelled or
otherwise terminated under any provision of this subchapter, the lessee,
upon our approval, may defer removal of any OCS facility within the
lease area that is subject to an Alternate Use RUE. If we elect to grant
such a deferral, the lessee remains responsible for removing the
facility upon termination of the Alternate Use RUE and will be required
to retain sufficient bonding or other financial assurances to ensure
that the structure is removed or otherwise decommissioned in accordance
with the provisions of this subpart.

Site Clearance for Wells, Platforms, and Other Facilities

Sec. 250.1740 How must I verify that the site of a permanently plugged well,
removed platform, or other removed facility is clear of obstructions?

Within 60 days after you permanently plug a well or remove a
platform or other facility, you must verify that the site is clear of
obstructions by using one of the following methods:
(a) For a well site, you must either:
(1) Drag a trawl over the site;
(2) Scan across the location using sonar equipment;
(3) Inspect the site using a diver;
(4) Videotape the site using a camera on a remotely operated vehicle
(ROV); or
(5) Use another method approved by the District Manager if the
particular site conditions warrant.
(b) For a platform or other facility site in water depths less than
300 feet, you must drag a trawl over the site.
(c) For a platform or other facility site in water depths 300 feet
or more, you must either:
(1) Drag a trawl over the site;

[[Page 272]]

(2) Scan across the site using sonar equipment; or
(3) Use another method approved by the Regional Supervisor if the
particular site conditions warrant.

Sec. 250.1741 If I drag a trawl across a site, what requirements must I meet?

If you drag a trawl across the site in accordance with Sec.
250.1740, you must meet all of the requirements of this section.
(a) You must drag the trawl in a grid-like pattern as shown in the
following table:

------------------------------------------------------------------------
You must drag the trawl
For a . . . across a . . .
------------------------------------------------------------------------
(1) Well site, 300-foot-radius circle
centered on the well
location.
(2) Subsea well site, 600-foot-radius circle
centered on the well
location.
(3) Platform site, 1,320-foot-radius circle
centered on the location of
the platform.
(4) Single-well caisson, well protector 600-foot-radius circle
jacket, template, or manifold, centered on the structure
location.
------------------------------------------------------------------------

(b) You must trawl 100 percent of the limits described in paragraph
(a) of this section in two directions.
(c) You must mark the area to be cleared as a hazard to navigation
according to USCG requirements until you complete the site clearance
procedures.
(d) You must use a trawling vessel equipped with a calibrated
navigational positioning system capable of providing position accuracy
of 30 feet.
(e) You must use a trawling net that is representative of those used
in the commercial fishing industry (one that has a net strength equal or
greater than that provided by No. 18 twine).
(f) You must ensure that you trawl no closer than 300 feet from a
shipwreck, and 500 feet from a sensitive biological feature.
(g) If you trawl near an active pipeline, you must meet the
requirements in the following table:

----------------------------------------------------------------------------------------------------------------
For . . . You must trawl . . . And you must . . .
----------------------------------------------------------------------------------------------------------------
(1) Buried active pipelines, ........................................ First contact the pipeline
owner or operator to
determine the condition of
the pipeline before
trawling over the buried
pipeline.
(2) Unburied active pipelines that are 8 no closer than 100 feet to the either Trawl parallel to the
inches in diameter or larger, side of the pipeline, pipeline Do not trawl
across the pipeline.
(3) Unburied smaller diameter active no closer than 100 feet to either side Trawl parallel to the
pipelines in the trawl area that have of the pipeline, pipeline. Do not trawl
obstructions (e.g., pipeline valves) across the pipeline.
present,
(4) Unburied active pipelines in the parallel to the pipeline, ...........................
trawl area that are smaller than 8
inches in diameter and have no
obstructions present,
----------------------------------------------------------------------------------------------------------------

(h) You must ensure that any trawling contractor you may use:
(1) Has no corporate or other financial ties to you; and
(2) Has a valid commercial trawling license for both the vessel and
its captain.

Sec. 250.1742 What other methods can I use to verify that a site is clear?

If you do not trawl a site, you can verify that the site is clear of
obstructions by using any of the methods shown in the following table:

----------------------------------------------------------------------------------------------------------------
If you use . . . You must . . . And you must . . .
----------------------------------------------------------------------------------------------------------------
(a) Sonar, cover 100 percent of the appropriate Use a sonar signal with a
grid area listed in Sec. 250.1741(a), frequency of at least 500
kHz.

[[Page 273]]

(b) A diver, ensure that the diver visually inspects Ensure that the diver uses
100 percent of the appropriate grid a search pattern of
area listed in Sec. 250.1741(a), concentric circles or
parallel lines spaced no
more than 10 feet apart.
(c) An ROV (remotely operated vehicle), ensure that the ROV camera records Ensure that the ROV uses a
videotape over 100 percent of the pattern of concentric
appropriate grid area listed in Sec. circles or parallel lines
250.1741(a), spaced no more than 10
feet apart.
----------------------------------------------------------------------------------------------------------------

Sec. 250.1743 How do I certify that a site is clear of obstructions?

(a) For a well site, you must submit to the appropriate District
Manager within 30 days after you complete the verification activities a
form BSEE-0124, Application for Permit to Modify, to include the
following information:
(1) A signed certification that the well site area is cleared of all
obstructions;
(2) The date the verification work was performed and the vessel
used;
(3) The extent of the area surveyed;
(4) The survey method used;
(5) The results of the survey, including a list of any debris
removed or a statement from the trawling contractor that no objects were
recovered; and
(6) A post-trawling job plot or map showing the trawled area.
(b) For a platform or other facility site, you must submit the
following information to the appropriate Regional Supervisor within 30
days after you complete the verification activities:
(1) A letter signed by an authorized company official certifying
that the platform or other facility site area is cleared of all
obstructions and that a company representative witnessed the
verification activities;
(2) A letter signed by an authorized official of the company that
performed the verification work for you certifying that it cleared the
platform or other facility site area of all obstructions;
(3) The date the verification work was performed and the vessel
used;
(4) The extent of the area surveyed;
(5) The survey method used;
(6) The results of the survey, including a list of any debris
removed or a statement from the trawling contractor that no objects were
recovered; and
(7) A post-trawling job plot or map showing the trawled area.

Pipeline Decommissioning

Sec. 250.1750 When may I decommission a pipeline in place?

You may decommission a pipeline in place when the Regional
Supervisor determines that the pipeline does not constitute a hazard
(obstruction) to navigation and commercial fishing operations, unduly
interfere with other uses of the OCS, or have adverse environmental
effects.

Sec. 250.1751 How do I decommission a pipeline in place?

You must do the following to decommission a pipeline in place:
(a) Submit a pipeline decommissioning application in triplicate to
the Regional Supervisor for approval. Your application must be
accompanied by payment of the service fee listed in Sec. 250.125. Your
application must include the following information:
(1) Reason for the operation;
(2) Proposed decommissioning procedures;
(3) Length (feet) of segment to be decommissioned; and
(4) Length (feet) of segment remaining.
(b) Pig the pipeline, unless the Regional Supervisor determines that
pigging is not practical;
(c) Flush the pipeline;
(d) Fill the pipeline with seawater;
(e) Cut and plug each end of the pipeline;
(f) Bury each end of the pipeline at least 3 feet below the seafloor
or cover each end with protective concrete mats, if required by the
Regional Supervisor; and
(g) Remove all pipeline valves and other fittings that could unduly
interfere with other uses of the OCS.

[[Page 274]]

Sec. 250.1752 How do I remove a pipeline?

Before removing a pipeline, you must:
(a) Submit a pipeline removal application in triplicate to the
Regional Supervisor for approval. Your application must be accompanied
by payment of the service fee listed in Sec. 250.125. Your application
must include the following information:
(1) Proposed removal procedures;
(2) If the Regional Supervisor requires it, a description, including
anchor pattern(s), of the vessel(s) you will use to remove the pipeline;
(3) Length (feet) to be removed;
(4) Length (feet) of the segment that will remain in place;
(5) Plans for transportation of the removed pipe for disposal or
salvage;
(6) Plans to protect archaeological and sensitive biological
features during removal operations, including a brief assessment of the
environmental impacts of the removal operations and procedures and
mitigation measures that you will take to minimize such impacts; and
(7) Projected removal schedule and duration.
(b) Pig the pipeline, unless the Regional Supervisor determines that
pigging is not practical; and
(c) Flush the pipeline.

Sec. 250.1753 After I decommission a pipeline, what information
must I submit?

Within 30 days after you decommission a pipeline, you must submit a
written report to the Regional Supervisor that includes the following:
(a) A summary of the decommissioning operation including the date it
was completed;
(b) A description of any mitigation measures you took; and
(c) A statement signed by your authorized representative that
certifies that the pipeline was decommissioned according to the approved
application.

Sec. 250.1754 When must I remove a pipeline decommissioned in place?

You must remove a pipeline decommissioned in place if the Regional
Supervisor determines that the pipeline is an obstruction.

Subpart R [Reserved]

Subpart S_Safety and Environmental Management Systems (SEMS)

Sec. 250.1900 Must I have a SEMS program?

You must develop, implement, and maintain a safety and environmental
management system (SEMS) program. Your SEMS program must address the
elements described in Sec. 250.1902, American Petroleum Institute's
Recommended Practice for Development of a Safety and Environmental
Management Program for Offshore Operations and Facilities (API RP 75)
(as incorporated by reference in Sec. 250.198), and other requirements
as identified in this subpart.
(a) If there are any conflicts between the requirements of this
subpart and API RP 75; COS-2-01, COS-2-03, or COS-2-04; or ISO/IEC 17011
(incorporated by reference as specified in Sec. 250.198), you must
follow the requirements of this subpart.
(b) Nothing in this subpart affects safety or other matters under
the jurisdiction of the Coast Guard.

[76 FR 64462, Oct. 18, 2011, as amended at 78 FR 20440, Apr. 5, 2013]

Sec. 250.1901 What is the goal of my SEMS program?

The goal of your SEMS program is to promote safety and environmental
protection by ensuring all personnel aboard a facility are complying
with the policies and procedures identified in your SEMS.
(a) To accomplish this goal, you must ensure that your SEMS program
identifies, addresses, and manages safety, environmental hazards, and
impacts during the design, construction, start-up, operation (including,
but not limited to, drilling and decommissioning), inspection, and
maintenance of all new and existing facilities, including mobile
offshore drilling units (MODUs) when attached to the seabed and
Department of the Interior (DOI) regulated pipelines.
(b) All personnel involved with your SEMS program must be trained to
have

[[Page 275]]

the skills and knowledge to perform their assigned duties.

[76 FR 64462, Oct. 18, 2011, as amended at 78 FR 20440, Apr. 5, 2013]

Sec. 250.1902 What must I include in my SEMS program?

You must have a properly documented SEMS program in place and make
it available to BSEE upon request as required by Sec. 250.1924(b).
(a) Your SEMS program must meet the minimum criteria outlined in
this subpart, including the following SEMS program elements:
(1) General (see Sec. 250.1909)
(2) Safety and Environmental Information (see Sec. 250.1910)
(3) Hazards Analysis (see Sec. 250.1911)
(4) Management of Change (see Sec. 250.1912)
(5) Operating Procedures (see Sec. 250.1913)
(6) Safe Work Practices (see Sec. 250.1914)
(7) Training (see Sec. 250.1915)
(8) Mechanical Integrity (Assurance of Quality and Mechanical
Integrity of Critical Equipment) (see Sec. 250.1916)
(9) Pre-startup Review (see Sec. 250.1917)
(10) Emergency Response and Control (see Sec. 250.1918)
(11) Investigation of Incidents (see Sec. 250.1919)
(12) Auditing (Audit of Safety and Environmental Management Program
Elements) (see Sec. 250.1920)
(13) Recordkeeping (Records and Documentation) and additional BSEE
requirements (see Sec. 250.1928)
(14) Stop Work Authority (SWA) (see Sec. 250.1930)
(15) Ultimate Work Authority (UWA) (see Sec. 250.1931)
(16) Employee Participation Plan (EPP) (see Sec. 250.1932)
(17) Reporting Unsafe Working Conditions (see Sec. 250.1933).
(b) You must include a job safety analysis (JSA) for OCS activities
identified or discussed in your SEMS program (see Sec. 250.1911).
(c) Your SEMS program must meet or exceed the standards of safety
and environmental protection of API RP 75 (as incorporated by reference
in Sec. 250.198).

[76 FR 64462, Oct. 18, 2011, as amended at 78 FR 20440, Apr. 5, 2013]

Sec. 250.1903 Acronyms and definitions.

Definitions listed in this section apply to this subpart and
supersede definitions in API RP 75, Appendices D and E; COS-2-01, COS-2-
03, and COS-2-04; and ISO/IEC 17011 (incorporated by reference as
specified in Sec. 250.198).
(a) Acronyms used frequently in this subpart have the following
meanings:
AB means Accreditation Body,
ASP means Audit Service Provider,
CAP means Corrective Action Plan,
COS means Center for Offshore Safety,
EPP means Employee Participation Plan,
ISO means International Organization for Standardization,
JSA means Job Safety Analysis,
MODU means Mobile Offshore Drilling Unit,
OCS means Outer Continental Shelf,
SEMS means Safety and Environmental Management Systems,
SWA means Stop Work Authority,
USCG means United States Coast Guard, and
UWA means Ultimate Work Authority.
(b) Terms used in this subpart are listed alphabetically as follows:
Accreditation Body (AB) means a BSEE-approved independent third-
party organization that assesses and accredits ASPs.
Audit Service Provider (ASP) means an independent third-party
organization that demonstrates competence to conduct SEMS audits in
accordance with the requirements of this subpart.
Corrective Action Plan (CAP) means a scheduled plan to correct
deficiencies identified during an audit and that is developed by an
operator following the issuance of an audit report.
Personnel means direct employee(s) of the operator and contracted
workers.
Ultimate Work Authority (UWA) means the authority assigned to an
individual or position to make final decisions relating to activities
and operations on the facility.

[76 FR 64462, Oct. 18, 2011, as amended at 78 FR 20440, Apr. 5, 2013]

Sec. 250.1904 Special instructions.

(a) For purposes of this subpart, each and every reference in COS-2-
01, COS-

[[Page 276]]

2-03, and COS-2-04 (incorporated by reference as specified in Sec.
250.198) to the term deepwater means the entire OCS, including all water
depths.
(b) The BSEE does not incorporate by reference any requirement that
you must be a COS member company. For purposes of this subpart, each and
every reference in COS-2-01, COS-2-03, and COS-2-04 to the phrase COS
member company(ies) means you, whether or not you are a COS member.
(c) For purposes of this subpart, each and every reference in the
relevant sections of COS-2-01, COS-2-03, and COS-2-04 (incorporated by
reference as specified in Sec. 250.198) to the Center for Offshore
Safety or COS means accreditation body or AB.
(d) For purposes of this subpart, each and every reference in ISO/
IEC 17011 (incorporated by reference as specified in Sec. 250.198) to
conformity assessment body (CAB) means ASP.

[78 FR 20441, Apr. 5, 2013]

Sec. Sec. 250.1905-250.1908 [Reserved]

Sec. 250.1909 What are management's general responsibilities
for the SEMS program?

You, through your management, must require that the program elements
discussed in API RP 75 (as incorporated by reference in Sec. 250.198)
and in this subpart are properly documented and are available at field
and office locations, as appropriate for each program element. You,
through your management, are responsible for the development, support,
continued improvement, and overall success of your SEMS program.
Specifically you, through your management, must:
(a) Establish goals and performance measures, demand accountability
for implementation, and provide necessary resources for carrying out an
effective SEMS program.
(b) Appoint management representatives who are responsible for
establishing, implementing and maintaining an effective SEMS program.
(c) Designate specific management representatives who are
responsible for reporting to management on the performance of the SEMS
program.
(d) At intervals specified in the SEMS program and at least
annually, review the SEMS program to determine if it continues to be
suitable, adequate and effective (by addressing the possible need for
changes to policy, objectives, and other elements of the program in
light of program audit results, changing circumstances and the
commitment to continual improvement) and document the observations,
conclusions and recommendations of that review.
(e) Develop and endorse a written description of your safety and
environmental policies and organizational structure that define
responsibilities, authorities, and lines of communication required to
implement the SEMS program.
(f) Utilize personnel with expertise in identifying safety hazards,
environmental impacts, optimizing operations, developing safe work
practices, developing training programs and investigating incidents.
(g) Ensure that facilities are designed, constructed, maintained,
monitored, and operated in a manner compatible with applicable industry
codes, consensus standards, and generally accepted practice as well as
in compliance with all applicable governmental regulations.
(h) Ensure that management of safety hazards and environmental
impacts is an integral part of the design, construction, maintenance,
operation, and monitoring of each facility.
(i) Ensure that suitably trained and qualified personnel are
employed to carry out all aspects of the SEMS program.
(j) Ensure that the SEMS program is maintained and kept up to date
by means of periodic audits to ensure effective performance.

Sec. 250.1910 What safety and environmental information is required?

(a) You must require that SEMS program safety and environmental
information be developed and maintained for any facility that is subject
to the SEMS program.
(b) SEMS program safety and environmental information must include:
(1) Information that provides the basis for implementing all SEMS
program elements, including the requirements of hazard analysis (Sec.
250.1911);

[[Page 277]]

(2) process design information including, as appropriate, a
simplified process flow diagram and acceptable upper and lower limits,
where applicable, for items such as temperature, pressure, flow and
composition; and
(3) mechanical design information including, as appropriate, piping
and instrument diagrams; electrical area classifications; equipment
arrangement drawings; design basis of the relief system; description of
alarm, shutdown, and interlock systems; description of well control
systems; and design basis for passive and active fire protection
features and systems and emergency evacuation procedures.

Sec. 250.1911 What hazards analysis criteria must my SEMS program meet?

You must ensure that a hazards analysis (facility level) and a JSA
(operations/task level) are developed and implemented for all of your
facilities and activities identified or discussed in your SEMS. You must
document and maintain a current analysis for each operation covered by
this section for the life of the operation at the facility. You must
update the analysis when an internal audit is conducted to ensure that
it is consistent with your facility's current operations.
(a) Hazards analysis (facility level). The hazards analysis must be
appropriate for the complexity of the operation and must identify,
evaluate, and manage the hazards involved in the operation.
(1) The hazards analysis must address the following:
(i) Hazards of the operation;
(ii) Previous incidents related to the operation you are evaluating,
including any incident in which you were issued an Incident of
Noncompliance or a civil or criminal penalty;
(iii) Control technology applicable to the operation your hazards
analysis is evaluating; and
(iv) A qualitative evaluation of the possible safety and health
effects on employees, and potential impacts to the human and marine
environments, which may result if the control technology fails.
(2) The hazards analysis must be performed by a person(s) with
experience in the operations being evaluated. These individuals also
need to be experienced in the hazards analysis methodologies being
employed.
(3) You should assure that the recommendations in the hazards
analysis are resolved and that the resolution is documented.
(4) A single hazards analysis can be performed to fulfill the
requirements for simple and nearly identical facilities, such as well
jackets and single well caissons. You can apply this single hazards
analysis to simple and nearly identical facilities after you verify that
any site-specific deviations are addressed in each of your SEMS program
elements.
(b) JSA. You must ensure a JSA is prepared, conducted, and approved
for OCS activities that are identified or discussed in your SEMS
program. The JSA is a technique used to identify risks to personnel
associated with their job activities. The JSAs are also used to
determine the appropriate mitigation measures needed to reduce job risks
to personnel. The JSA must include all personnel involved with the job
activity.
(1) You must ensure that your JSA identifies, analyzes, and records:
(i) The steps involved in performing a specific job;
(ii) The existing or potential safety, health, and environmental
hazards associated with each step; and
(iii) The recommended action(s) and/or procedure(s) that will
eliminate or reduce these hazards, the risk of a workplace injury or
illness, or environmental impacts.
(2) The immediate supervisor of the crew performing the job onsite
must conduct the JSA, sign the JSA, and ensure that all personnel
participating in the job understand and sign the JSA.
(3) The individual you designate as being in charge of the facility
must approve and sign all JSAs before personnel start the job.
(4) If a particular job is conducted on a recurring basis, and if
the parameters of these recurring jobs do not change, then the person in
charge of the job may decide that a JSA for each individual job is not
required. The parameters you must consider in making this

[[Page 278]]

determination include, but are not limited to, changes in personnel,
procedures, equipment, and environmental conditions associated with the
job.
(c) All personnel, which includes contractors, must be trained in
accordance with the requirements of Sec. 250.1915. You must also verify
that contractors are trained in accordance with Sec. 250.1915 prior to
performing a job.

[76 FR 64462, Oct. 18, 2011, as amended at 78 FR 20441, Apr. 5, 2013]

Sec. 250.1912 What criteria for management of change
must my SEMS program meet?

(a) You must develop and implement written management of change
procedures for modifications associated with the following:
(1) Equipment,
(2) Operating procedures,
(3) Personnel changes (including contractors),
(4) Materials, and
(5) Operating conditions.
(b) Management of change procedures do not apply to situations
involving replacement in kind (such as, replacement of one component by
another component with the same performance capabilities).
(c) You must review all changes prior to their implementation.
(d) The following items must be included in your management of
change procedures:
(1) The technical basis for the change;
(2) Impact of the change on safety, health, and the coastal and
marine environments;
(3) Necessary time period to implement the change; and
(4) Management approval procedures for the change.
(e) Employees, including contractors whose job tasks will be
affected by a change in the operation, must be informed of, and trained
in, the change prior to startup of the process or affected part of the
operation; and
(f) If a management of change results in a change in the operating
procedures of your SEMS program, such changes must be documented and
dated.

Sec. 250.1913 What criteria for operating procedures
must my SEMS program meet?

(a) You must develop and implement written operating procedures that
provide instructions for conducting safe and environmentally sound
activities involved in each operation addressed in your SEMS program.
These procedures must include the job title and reporting relationship
of the person or persons responsible for each of the facility's
operating areas and address the following:
(1) Initial startup;
(2) Normal operations;
(3) All emergency operations (including but not limited to medical
evacuations, weather-related evacuations and emergency shutdown
operations);
(4) Normal shutdown;
(5) Startup following a turnaround, or after an emergency shutdown;
(6) Bypassing and flagging out-of-service equipment;
(7) Safety and environmental consequences of deviating from your
equipment operating limits and steps required to correct or avoid this
deviation;
(8) Properties of, and hazards presented by, the chemicals used in
the operations;
(9) Precautions you will take to prevent the exposure of chemicals
used in your operations to personnel and the environment. The
precautions must include control technology, personal protective
equipment, and measures to be taken if physical contact or airborne
exposure occurs;
(10) Raw materials used in your operations and the quality control
procedures you used in purchasing these raw materials;
(11) Control of hazardous chemical inventory; and
(12) Impacts to the human and marine environment identified through
your hazards analysis.
(b) Operating procedures must be accessible to all employees
involved in the operations.
(c) Operating procedures must be reviewed at the conclusion of
specified periods and as often as necessary to assure they reflect
current and actual operating practices, including any changes made to
your operations.

[[Page 279]]

(d) You must develop and implement safe and environmentally sound
work practices for identified hazards during operations and the degree
of hazard presented.
(e) Review of and changes to the procedures must be documented and
communicated to responsible personnel.

Sec. 250.1914 What criteria must be documented in my SEMS program
for safe work practices and contractor selection?

Your SEMS program must establish and implement safe work practices
designed to minimize the risks associated with operations, maintenance,
modification activities, and the handling of materials and substances
that could affect safety or the environment. Your SEMS program must also
document contractor selection criteria. When selecting a contractor, you
must obtain and evaluate information regarding the contractor's safety
record and environmental performance. You must ensure that contractors
have their own written safe work practices. Contractors may adopt
appropriate sections of your SEMS program. You and your contractor must
document an agreement on appropriate contractor safety and environmental
policies and practices before the contractor begins work at your
facilities.
(a) A contractor is anyone performing work for you. However, these
requirements do not apply to contractors providing domestic services to
you or other contractors. Domestic services include janitorial work,
food and beverage service, laundry service, housekeeping, and similar
activities.
(b) You must document that your contracted employees are
knowledgeable and experienced in the work practices necessary to perform
their job in a safe and environmentally sound manner. Documentation of
each contracted employee's expertise to perform his/her job and a copy
of the contractor's safety policies and procedures must be made
available to the operator and BSEE upon request.
(c) Your SEMS program must include procedures and verification for
selecting a contractor as follows:
(1) Your SEMS program must have procedures that verify that
contractors are conducting their activities in accordance with your SEMS
program.
(2) You are responsible for making certain that contractors have the
skills and knowledge to perform their assigned duties and are conducting
these activities in accordance with the requirements in your SEMS
program.
(3) You must make the results of your verification for selecting
contractors available to BSEE upon request.
(d) Your SEMS program must include procedures and verification that
contractor personnel understand and can perform their assigned duties
for activities such as, but not limited to:
(1) Installation, maintenance, or repair of equipment;
(2) Construction, startup, and operation of your facilities;
(3) Turnaround operations;
(4) Major renovation; or
(5) Specialty work.
(e) You must:
(1) Perform periodic evaluations of the performance of contract
employees that verifies they are fulfilling their obligations, and
(2) Maintain a contractor employee injury and illness log for 2
years related to the contractor's work in the operation area, and
include this information on Form BSEE-0131.
(f) You must inform your contractors of any known hazards at the
facility they are working on including, but not limited to fires,
explosions, slips, trips, falls, other injuries, and hazards associated
with lifting operations.
(g) You must develop and implement safe work practices to control
the presence, entrance, and exit of contract employees in operation
areas.

[76 FR 64462, Oct. 18, 2011, as amended at 78 FR 20441, Apr. 5, 2013]

Sec. 250.1915 What training criteria must be in my SEMS program?

Your SEMS program must establish and implement a training program so
that all personnel are trained in accordance with their duties and
responsibilities to work safely and are aware of potential environmental
impacts. Training must address such areas as operating procedures (Sec.
250.1913), safe work practices (Sec. 250.1914), emergency response and
control measures (Sec. 250.1918), SWA (Sec. 250.1930), UWA

[[Page 280]]

(Sec. 250.1931), EPP (Sec. 250.1932), reporting unsafe working
conditions (Sec. 250.1933), and how to recognize and identify hazards
and how to construct and implement JSAs (Sec. 250.1911). You must
document your instructors' qualifications. Your SEMS program must
address:
(a) Initial training for the basic well-being of personnel and
protection of the environment, and ensure that persons assigned to
operate and maintain the facility possess the required knowledge and
skills to carry out their duties and responsibilities, including startup
and shutdown.
(b) Periodic training to maintain understanding of, and adherence
to, the current operating procedures, using periodic drills, to verify
adequate retention of the required knowledge and skills.
(c) Communication requirements to ensure that personnel will be
informed of and trained as outlined in this section whenever a change is
made in any of the areas in your SEMS program that impacts their ability
to properly understand and perform their duties and responsibilities.
Training and/or notice of the change must be given before personnel are
expected to operate the facility.
(d) How you will verify that the contractors are trained in the work
practices necessary to understand and perform their jobs in a safe and
environmentally sound manner in accordance with all provisions of this
section.

[76 FR 64462, Oct. 18, 2011, as amended at 78 FR 20441, Apr. 5, 2013]

Sec. 250.1916 What criteria for mechanical integrity
must my SEMS program meet?

You must develop and implement written procedures that provide
instructions to ensure the mechanical integrity and safe operation of
equipment through inspection, testing, and quality assurance. The
purpose of mechanical integrity is to ensure that equipment is fit for
service. Your mechanical integrity program must encompass all equipment
and systems used to prevent or mitigate uncontrolled releases of
hydrocarbons, toxic substances, or other materials that may cause
environmental or safety consequences. These procedures must address the
following:
(a) The design, procurement, fabrication, installation, calibration,
and maintenance of your equipment and systems in accordance with the
manufacturer's design and material specifications.
(b) The training of each employee involved in maintaining your
equipment and systems so that your employees can implement your
mechanical integrity program.
(c) The frequency of inspections and tests of your equipment and
systems. The frequency of inspections and tests must be in accordance
with BSEE regulations and meet the manufacturer's recommendations.
Inspections and tests can be performed more frequently if determined to
be necessary by prior operating experience.
(d) The documentation of each inspection and test that has been
performed on your equipment and systems. This documentation must
identify the date of the inspection or test; include the name and
position, and the signature of the person who performed the inspection
or test; include the serial number or other identifier of the equipment
on which the inspection or test was performed; include a description of
the inspection or test performed; and the results of the inspection
test.
(e) The correction of deficiencies associated with equipment and
systems that are outside the manufacturer's recommended limits. Such
corrections must be made before further use of the equipment and system.
(f) The installation of new equipment and constructing systems. The
procedures must address the application for which they will be used.
(g) The modification of existing equipment and systems. The
procedures must ensure that they are modified for the application for
which they will be used.
(h) The verification that inspections and tests are being performed.
The procedures must be appropriate to ensure that equipment and systems
are installed consistent with design specifications and the
manufacturer's instructions.

[[Page 281]]

(i) The assurance that maintenance materials, spare parts, and
equipment are suitable for the applications for which they will be used.

Sec. 250.1917 What criteria for pre-startup review must be
in my SEMS program?

Your SEMS program must require that the commissioning process
include a pre-startup safety and environmental review for new and
significantly modified facilities that are subject to this subpart to
confirm that the following criteria are met:
(a) Construction and equipment are in accordance with applicable
specifications.
(b) Safety, environmental, operating, maintenance, and emergency
procedures are in place and are adequate.
(c) Safety and environmental information is current.
(d) Hazards analysis recommendations have been implemented as
appropriate.
(e) Training of operating personnel has been completed.
(f) Programs to address management of change and other elements of
this subpart are in place.
(g) Safe work practices are in place.

Sec. 250.1918 What criteria for emergency response and control must be
in my SEMS program?

Your SEMS program must require that emergency response and control
plans are in place and are ready for immediate implementation. These
plans must be validated by drills carried out in accordance with a
schedule defined by the SEMS training program (Sec. 250.1915). The SEMS
emergency response and control plans must include:
(a) Emergency Action Plan that assigns authority and responsibility
to the appropriate qualified person(s) at a facility for initiating
effective emergency response and control, addressing emergency reporting
and response requirements, and complying with all applicable
governmental regulations;
(b) Emergency Control Center(s) designated for each facility with
access to the Emergency Action Plans, oil spill contingency plan, and
other safety and environmental information (Sec. 250.1910); and
(c) Training and Drills incorporating emergency response and
evacuation procedures conducted periodically for all personnel
(including contractor's personnel), as required by the SEMS training
program (Sec. 250.1915). Drills must be based on realistic scenarios
conducted periodically to exercise elements contained in the facility or
area emergency action plan. An analysis and critique of each drill must
be conducted to identify and correct weaknesses.

Sec. 250.1919 What criteria for investigation of incidents must be
in my SEMS program?

To learn from incidents and help prevent similar incidents, your
SEMS program must establish procedures for investigation of all
incidents with serious safety or environmental consequences and require
investigation of incidents that are determined by facility management or
BSEE to have possessed the potential for serious safety or environmental
consequences. Incident investigations must be initiated as promptly as
possible, with due regard for the necessity of securing the incident
scene and protecting people and the environment. Incident investigations
must be conducted by personnel knowledgeable in the process involved,
investigation techniques, and other specialties that are relevant or
necessary.
(a) The investigation of an incident must address the following:
(1) The nature of the incident;
(2) The factors (human or other) that contributed to the initiation
of the incident and its escalation/control; and
(3) Recommended changes identified as a result of the investigation.
(b) A corrective action program must be established based on the
findings of the investigation in order to analyze incidents for common
root causes. The corrective action program must:
(1) Retain the findings of investigations for use in the next hazard
analysis update or audit;
(2) Determine and document the response to each finding to ensure
that corrective actions are completed; and

[[Page 282]]

(3) Implement a system whereby conclusions of investigations are
distributed to similar facilities and appropriate personnel within their
organization.

Sec. 250.1920 What are the auditing requirements for my SEMS program?

(a) Your SEMS program must be audited by an accredited ASP according
to the requirements of this subpart and API RP 75, Section 12
(incorporated by reference as specified in Sec. 250.198). The audit
process must also meet or exceed the criteria in Sections 9.1 through
9.8 of Requirements for Third-party SEMS Auditing and Certification of
Deepwater Operations COS-2-03 (incorporated by reference as specified in
Sec. 250.198) or its equivalent. Additionally, the audit team lead must
be an employee, representative, or agent of the ASP, and must not have
any affiliation with the operator. The remaining team members may be
chosen from your personnel and those of the ASP. The audit must be
comprehensive and include all elements of your SEMS program. It must
also identify safety and environmental performance deficiencies.
(b) Your audit plan and procedures must meet or exceed all of the
recommendations included in API RP 75 section 12 (as specified in Sec.
250.198) and include information on how you addressed those
recommendations. You must specifically address the following items:
(1) Section 12.1 General.
(2) Section 12.2 Scope.
(3) Section 12.3 Audit Coverage.
(4) Section 12.4 Audit Plan. You must submit your written Audit Plan
to BSEE at least 30 days before the audit. BSEE reserves the right to
modify the list of facilities that you propose to audit.
(5) Section 12.5 Audit Frequency. You must have your SEMS program
audited by an ASP within 2 years after initial implementation and every
3 years thereafter. The 3-year auditing cycle begins on the start date
of each comprehensive audit (including the initial implementation audit)
and ends on the start date of your next comprehensive audit. For
exploratory drilling operations taking place on the Arctic OCS, you must
conduct an audit, consisting of an onshore portion and an offshore
portion, including all related infrastructure, once per year for every
year in which drilling is conducted.
(6) Section 12.6 Audit Team. Your audits must be performed by an ASP
as described in Sec. 250.1921. You must include the ASP's
qualifications in your audit plan.
(c) You must submit an audit report of the audit findings,
observations, deficiencies identified, and conclusions to BSEE within 60
days of the audit completion date. For exploratory drilling operations
taking place on the Arctic OCS, you must submit an audit report of the
audit findings, observations, deficiencies and conclusions for the
onshore portion of your audit no later than March 1 in any year in which
you plan to drill, and for the offshore portion of your audit, within 30
days of the close of the audit.
(d) You must provide BSEE with a copy of your CAP for addressing the
deficiencies identified in your audit within 60 days of the audit
completion date. Your CAP must include the name and job title of the
personnel responsible for correcting the identified deficiency(ies). The
BSEE will notify you as soon as practicable after receipt of your CAP if
your proposed schedule is not acceptable or if the CAP does not
effectively address the audit findings. For exploratory drilling
operations taking place on the Arctic OCS, you must provide BSEE with a
copy of your CAP for addressing deficiencies or nonconformities
identified in the onshore portion of the audit no later than March 1 in
any year in which you plan to drill, and for the offshore portion of
your audit, within 30 days of the close of the audit.
(e) BSEE may verify that you undertook the corrective actions and
that these actions effectively address the audit findings.
(f) For exploratory drilling operations taking place on the Arctic
OCS, during the offshore portion of each audit, 100 percent of the
facilities operated must be audited while drilling activities are
underway. You must start and close the offshore portion of the audit for
each facility within 30 days after the first spudding of the well or

[[Page 283]]

entry into an existing wellbore for any purpose from that facility.
(g) For exploratory drilling operations taking place on the Arctic
OCS, if BSEE determines that the CAP or progress toward implementing the
CAP is not satisfactory, BSEE may order you to shut down all or part of
your operations.

[76 FR 64462, Oct. 18, 2011, as amended at 78 FR 20442, Apr. 5, 2013; 81
FR 36151, June 6, 2016; 81 FR 46563, July 15, 2016]

Sec. 250.1921 What qualifications must the ASP meet?

(a) The ASP must meet or exceed the qualifications, competency, and
training criteria contained in Section 3 and Sections 6 through 10 of
Qualification and Competence Requirements for Audit Teams and Auditors
Performing Third-party SEMS Audits of Deepwater Operations, COS-2-01,
(incorporated by reference as specified in Sec. 250.198) or its
equivalent;
(b) The ASP must be accredited by a BSEE-approved AB; and
(c) The ASP must perform an audit in accordance with 250.1920(a).

[78 FR 20442, Apr. 5, 2013]

Sec. 250.1922 What qualifications must an AB meet?

(a) In order for BSEE to approve an AB, the organization must
satisfy the requirements of the International Organization for
Standardization's (ISO/IEC 17011) Conformity assessment--General
requirements for accreditation bodies accrediting conformity assessment
bodies, First Edition 2004-09-01; Corrected Version 2005-02-15
(incorporated by reference as specified in Sec. 250.198) or its
equivalent.
(1) The AB must have an accreditation process that meets or exceeds
the requirements contained in Section 6 of Requirements for
Accreditation of Audit Service Providers Performing SEMS Audits and
Certification of Deepwater Operations, COS-2-04 (incorporated by
reference as specified in Sec. 250.198) or its equivalent, and other
requirements specified in this subpart. Organizations requesting
approval must submit documentation to BSEE describing the process for
assessing an ASP for accreditation and approving, maintaining, and
withdrawing the accreditation of an ASP. Requests for approval must be
sent to DOI/BSEE, ATTN: Chief, Office of Offshore Regulatory Programs,
381 Elden Street, HE-3314, Herndon, VA 20170.
(2) An AB may be subject to BSEE audits and other requirements
deemed necessary to verify compliance with the accreditation
requirements.
(b) An AB must have procedures in place to avoid conflicts of
interest with the ASP and make such information available to BSEE upon
request.

[78 FR 20442, Apr. 5, 2013]

Sec. 250.1923 [Reserved]

Sec. 250.1924 How will BSEE determine if my SEMS program is effective?

(a) The BSEE, or its authorized representative, may evaluate or
visit your facility(ies) to determine whether your SEMS program is in
place, addresses all required elements, is effective in protecting
worker safety and health and the environment, and preventing incidents.
The BSEE, or its authorized representative, may evaluate any and all
aspects of your SEMS program as outlined in this subpart. These
evaluations or visits may be random and may be based upon your
performance or that of your contractors.
(b) For the evaluations, you must make the following available to
BSEE upon request:
(1) Your SEMS program;
(2) Your audit team's qualifications;
(3) The SEMS audits conducted of your program;
(4) Documents or information relevant to whether you have addressed
and corrected the deficiencies of your audit; and
(5) Other relevant documents or information.
(c) During the site visit BSEE may verify that:
(1) Personnel are following your SEMS program,
(2) You can explain and demonstrate the procedures and policies
included in your SEMS program; and
(3) You can produce evidence to support the implementation of your
SEMS program.

[76 FR 64462, Oct. 18, 2011, as amended at 78 FR 20442, Apr. 5, 2013]

[[Page 284]]

Sec. 250.1925 May BSEE direct me to conduct additional audits?

(a) The BSEE may direct you to have an ASP audit of your SEMS
program if BSEE identifies safety or non-compliance concerns based on
the results of our inspections and evaluations, or as a result of an
event. This BSEE-directed audit is in addition to the regular audit
required by Sec. 250.1920. Alternatively, BSEE may conduct an audit.
(1) If BSEE directs you to have an ASP audit, you are responsible
for all of the costs associated with the audit, and
(i) The ASP must meet the requirements of Sec. Sec. 250.1920 and
250.1921 of this subpart.
(ii) You must submit an audit report of the audit findings,
observations, deficiencies identified, and conclusions to BSEE within 60
days of the audit completion date.
(2) If BSEE conducts the audit, BSEE will provide you with a report
of the audit findings, observations, deficiencies identified, and
conclusions as soon as practicable.
(b) You must provide BSEE a copy of your CAP for addressing the
deficiencies identified in the BSEE-directed audit within 60 days of the
audit completion date. Your CAP must include the name and job title of
the personnel responsible for correcting the identified deficiency(ies).
The BSEE will notify you as soon as practicable after receipt of your
CAP if your proposed schedule is not acceptable or if the CAP does not
effectively address the audit findings.

[78 FR 20442, Apr. 5, 2013]

Sec. 250.1926 [Reserved]

Sec. 250.1927 What happens if BSEE finds shortcomings in my SEMS program?

If BSEE determines that your SEMS program is not in compliance with
this subpart we may initiate one or more of the following enforcement
actions:
(a) Issue an Incident(s) of Noncompliance;
(b) Assess civil penalties; or
(c) Initiate probationary or disqualification procedures from
serving as an OCS operator.

Sec. 250.1928 What are my recordkeeping and documentation requirements?

(a) Your SEMS program procedures must ensure that records and
documents are maintained for a period of 6 years, except as provided
below. You must document and keep all SEMS audits for 6 years and make
them available to BSEE upon request. You must maintain a copy of all
SEMS program documents at an onshore location.
(b) For JSAs, the person in charge of the job must document the
results of the JSA in writing and must ensure that records are kept
onsite for 30 days. In the case of a MODU, records must be kept onsite
for 30 days or until you release the MODU, whichever comes first. You
must retain these records for 2 years and make them available to BSEE
upon request.
(c) You must document and date all management of change provisions
as specified in Sec. 250.1912. You must retain these records for 2
years and make them available to BSEE upon request.
(d) You must keep your injury/illness log for 2 years and make them
available to BSEE upon request.
(e) You must keep all evaluations completed on contractor's safety
policies and procedures for 2 years and make them available to BSEE upon
request.
(f) For SWA, you must document all training and reviews required by
Sec. 250.1930(e). You must ensure that these records are kept onsite
for 30 days. In the case of a MODU, records must be kept onsite for 30
days or until you release the MODU, whichever comes first. You must
retain these records for 2 years and make them available to BSEE upon
request.
(g) For EPP, you must document your employees' participation in the
development and implementation of the SEMS program. You must retain
these records for 2 years and make them available to BSEE upon request.
(h) You must keep all records in an orderly manner, readily
identifiable, retrievable and legible, and include the date of any and
all revisions.

[76 FR 64462, Oct. 18, 2011, as amended at 78 FR 20442, Apr. 5, 2013]

[[Page 285]]

Sec. 250.1929 What are my responsibilities for submitting OCS
performance measure data?

You must submit Form BSEE-0131 on an annual basis by March 31st. The
form must be broken down quarterly, reporting the previous calendar
year's data.

Sec. 250.1930 What must be included in my SEMS program for SWA?

(a) Your SWA procedures must ensure the capability to immediately
stop work that is creating imminent risk or danger. These procedures
must grant all personnel the responsibility and authority, without fear
of reprisal, to stop work or decline to perform an assigned task when an
imminent risk or danger exists. Imminent risk or danger means any
condition, activity, or practice in the workplace that could reasonably
be expected to cause:
(1) Death or serious physical harm; or
(2) Significant environmental harm to:
(i) Land;
(ii) Air; or
(iii) Mineral deposits, marine, coastal, or human environment.
(b) The person in charge of the conducted work is responsible for
ensuring the work is stopped in an orderly and safe manner. Individuals
who receive a notification to stop work must comply with that direction
immediately.
(c) Work may be resumed when the individual on the facility with UWA
determines that the imminent risk or danger does not exist or no longer
exists. The decision to resume activities must be documented in writing
as soon as practicable.
(d) You must include SWA procedures and expectations as a standard
statement in all JSAs.
(e) You must conduct training on your SWA procedures as part of
orientations for all new personnel who perform activities on the OCS.
Additionally, the SWA procedures must be reviewed during all meetings
focusing on safety on facilities subject to this subpart.

[78 FR 20443, Apr. 5, 2013]

Sec. 250.1931 What must be included in my SEMS program for UWA?

(a) Your SEMS program must have a process to identify the individual
with the UWA on your facility(ies). You must designate this individual
taking into account all applicable USCG regulations that deal with
designating a person in charge of an OCS facility. Your SEMS program
must clearly define who is in charge at all times. In the event that
multiple facilities, including a MODU, are attached and working together
or in close proximity to one another to perform an OCS operation, your
SEMS program must identify the individual with the UWA over the entire
operation, including all facilities.
(b) You must ensure that all personnel clearly know who has UWA and
who is in charge of a specific operation or activity at all times,
including when that responsibility shifts to a different individual.
(c) The SEMS program must provide that if an emergency occurs that
creates an imminent risk or danger to the health or safety of an
individual, the public, or to the environment (as specified in Sec.
250.1930(a)), the individual with the UWA is authorized to pursue the
most effective action necessary in that individual's judgment for
mitigating and abating the conditions or practices causing the
emergency.

[78 FR 20443, Apr. 5, 2013]

Sec. 250.1932 What are my EPP requirements?

(a) Your management must consult with their employees on the
development, implementation, and modification of your SEMS program.
(b) Your management must develop a written plan of action regarding
how your appropriate employees, in both your offices and those working
on offshore facilities, will participate in your SEMS program
development and implementation.
(c) Your management must ensure that employees have access to
sections of your SEMS program that are relevant to their jobs.

[78 FR 20443, Apr. 5, 2013]

[[Page 286]]

Sec. 250.1933 What procedures must be included for reporting
unsafe working conditions?

(a) Your SEMS program must include procedures for all personnel to
report unsafe working conditions in accordance with Sec. 250.193. These
procedures must take into account applicable USCG reporting requirements
for unsafe working conditions.
(b) You must post a notice at the place of employment in a visible
location frequently visited by personnel that contains the reporting
information in Sec. 250.193.

[78 FR 20443, Apr. 5, 2013]

PART 251_GEOLOGICAL AND GEOPHYSICAL (G&G) EXPLORATIONS OF THE OUTER
CONTINENTAL SHELF--Table of Contents

Sec.
251.1 Definitions.
251.2 [Reserved]
251.3 Authority and applicability of this part.
251.4-251.6 [Reserved]
251.7 Test drilling activities under a permit.
251.8-251.14 [Reserved]
251.15 Authority for information collection.

Authority: 31 U.S.C. 9701, 43 U.S.C. 1334.

Source: 76 FR 64462, Oct. 18, 2011, unless otherwise noted.

Sec. 251.1 Definitions.

Terms used in this part have the following meaning:
Act means the Outer Continental Shelf Lands Act (OCSLA), as amended
(43 U.S.C. 1331 et seq.).
Analyzed geological information means data collected under a permit
or a lease that have been analyzed. Analysis may include, but is not
limited to, identification of lithologic and fossil content, core
analyses, laboratory analyses of physical and chemical properties, well
logs or charts, results from formation fluid tests, and descriptions of
hydrocarbon occurrences or hazardous conditions.
Archaeological interest means capable of providing scientific or
humanistic understanding of past human behavior, cultural adaptation,
and related topics through the application of scientific or scholarly
techniques, such as controlled observation, contextual measurements,
controlled collection, analysis, interpretation, and explanation.
Archaeological resources mean any material remains of human life or
activities that are at least 50 years of age and of archaeological
interest.
Coastal environment means the physical, atmospheric, and biological
components, conditions, and factors that interactively determine the
productivity, state, condition, and quality of the terrestrial ecosystem
from the shoreline inward to the boundaries of the coastal zone.
Coastal Zone means the coastal waters (including the lands therein
and thereunder) and the adjacent shorelands (including the waters
therein and thereunder), strongly influenced by each other and in
proximity to the shorelines of the several coastal States and extends
seaward to the outer limit of the U.S. territorial sea.
Coastal Zone Management Act means the Coastal Zone Management Act of
1972, as amended (16 U.S.C. 1451 et seq.).
Data means facts, statistics, measurements, or samples that have not
been analyzed, processed, or interpreted.
Deep stratigraphic test means drilling that involves the penetration
into the sea bottom of more than 500 feet (152 meters).
Director means the Director of the Bureau of Safety and
Environmental Enforcement, U.S. Department of the Interior, or a
subordinate authorized to act on the Director's behalf.
Exploration means the commercial search for oil, gas, and sulphur.
Activities classified as exploration include, but are not limited to:
(1) Geological and geophysical marine and airborne surveys where
magnetic, gravity, seismic reflection, seismic refraction, gas sniffers,
coring, or other systems are used to detect or imply the presence of
oil, gas, or sulphur; and
(2) Any drilling, whether on or off a geological structure.
Geological and geophysical scientific research means any oil, gas,
or sulphur related investigation conducted in the OCS for scientific
and/or research purposes. Geological, geophysical, and geochemical data
and information

[[Page 287]]

gathered and analyzed are made available to the public for inspection
and reproduction at the earliest practicable time. The term does not
include commercial geological or geophysical exploration or research.
Geological exploration means exploration that uses geological and
geochemical techniques (e.g., coring and test drilling, well logging,
and bottom sampling) to produce data and information on oil, gas, and
sulphur resources in support of possible exploration and development
activities. The term does not include geological scientific research.
Geological information means geological or geochemical data that
have been analyzed, processed, or interpreted.
Geophysical data means measurements that have not been processed or
interpreted.
Geophysical exploration means exploration that utilizes geophysical
techniques (e.g., gravity, magnetic, electromagnetic, or seismic) to
produce data and information on oil, gas, and sulphur resources in
support of possible exploration and development activities. The term
does not include geophysical scientific research.
Geophysical information means geophysical data that have been
processed or interpreted.
Governor means the Governor of a State or the person or entity
lawfully designated to exercise the powers granted to a Governor
pursuant to the Act.
Human environment means the physical, social, and economic
components, conditions, and factors which interactively determine the
state, condition, and quality of living conditions, employment, and
health of those affected, directly or indirectly, by activities
occurring on the OCS.
Hydrocarbon occurrence means the direct or indirect detection during
drilling operations of any liquid or gaseous hydrocarbons by examination
of well cuttings, cores, gas detector readings, formation fluid tests,
wireline logs, or by any other means. The term does not include
background gas, minor accumulations of gas, or heavy oil residues on
cuttings and cores.
Interpreted geological information means knowledge, often in the
form of schematic cross sections, 3-dimensional representations, and
maps, developed by determining the geological significance of geological
data and analyzed and processed geologic information.
Interpreted geophysical information means knowledge, often in the
form of seismic cross sections, 3-dimensional representations, and maps,
developed by determining the geological significance of geophysical data
and processed geophysical information.
Lease means an agreement which is issued under section 8 or
maintained under section 6 of the Act and which authorizes exploration
for, and development and production of, minerals or the area covered by
that authorization, whichever is required by the context.
Lessee means a person who has entered into, or is the BOEM approved
assignee of, a lease with the United States to explore for, develop, and
produce the leased minerals. The term ``lessee'' also includes an owner
of operating rights.
Marine environment means the physical, atmospheric, and biological
components, conditions, and factors that interactively determine the
quality of the marine ecosystem in the coastal zone and in the OCS.
Material remains mean physical evidence of human habitation,
occupation, use, or activity, including the site, location, or context
in which such evidence is situated.
Minerals mean oil, gas, sulphur, geopressured-geothermal and
associated resources, and all other minerals which are authorized by an
Act of Congress to be produced from public lands as defined in section
103 of the Federal Land Policy and Management Act of 1976 (43 U.S.C.
1702).
Notice means a written statement of intent to conduct geological or
geophysical scientific research related to oil, gas, and sulphur in the
OCS other than under a permit.
Oil, gas, and sulphur mean oil, gas, sulphur, geopressured-
geothermal, and associated resources.
Outer Continental Shelf (OCS) means all submerged lands lying
seaward and outside the area of lands beneath navigable waters as
defined in section 2 of the Submerged Lands Act (43 U.S.C.

[[Page 288]]

1301), and of which the subsoil and seabed appertain to the United
States and are subject to its jurisdiction and control.
Permit means the contract or agreement, other than a lease, issued
pursuant to this part, under which a person acquires the right to
conduct on the OCS, in accordance with appropriate statutes,
regulations, and stipulations:
(1) Geological exploration for mineral resources;
(2) Geophysical exploration for mineral resources;
(3) Geological scientific research; or
(4) Geophysical scientific research.
Permittee means the person authorized by a permit issued pursuant to
this part to conduct activities on the OCS.
Person means a citizen or national of the United States; an alien
lawfully admitted for permanent residence in the United States as
defined in section 8 U.S.C. 1101(a)(20); a private, public, or municipal
corporation organized under the laws of the United States or of any
State or territory thereof; and associations of such citizens,
nationals, resident aliens, or private, public, or municipal
corporations, States, or political subdivisions of States or anyone
operating in a manner provided for by treaty or other applicable
international agreements. The term does not include Federal agencies.
Processed geological or geophysical information means data collected
under a permit and later processed or reprocessed. Processing involves
changing the form of data so as to facilitate interpretation. Processing
operations may include, but are not limited to, applying corrections for
known perturbing causes, rearranging or filtering data, and combining or
transforming data elements. Reprocessing is the additional processing
other than ordinary processing used in the general course of evaluation.
Reprocessing operations may include varying identified parameters for
the detailed study of a specific problem area. Reprocessing may occur
several years after the original processing date. Reprocessing is
determined to be completed on the date that the reprocessed information
is first available in a useable format for in-house interpretation by
BOEM or the permittee, or becomes first available to third parties via
sale, trade, license agreement, or other means.
Secretary means the Secretary of the Interior or a subordinate
authorized to act on the Secretary's behalf.
Shallow test drilling means drilling into the sea bottom to depths
less than those specified in the definition of a deep stratigraphic
test.
Significant archaeological resource means those archaeological
resources that meet the criteria of significance for eligibility to the
National Register of Historic Places as defined in 36 CFR 60.4.
Third Party means any person other than the permittee or a
representative of the United States, including all persons who obtain
data or information acquired under a permit from the permittee, or from
another third party, by sale, trade, license agreement, or other means.
Violation means a failure to comply with any provision of the Act,
or a provision of a regulation or order issued under the Act, or any
provision of a lease, license, or permit issued under the Act.
You means a person who applies for and/or obtains a permit, or files
a Notice to conduct geological or geophysical exploration or scientific
research related to oil, gas, and sulphur in the OCS.

Sec. 251.2 [Reserved]

Sec. 251.3 Authority and applicability of this part.

BSEE authorizes you to conduct exploration or scientific research
activities under this part in accordance with the Act, the regulations
in this part, orders of the Director/Regional Director, and other
applicable statutes, regulations, and amendments.
(a) This part does not apply to G&G exploration conducted by or on
behalf of the lessee on a lease in the OCS. Refer to 30 CFR part 550 if
you plan to conduct G&G activities related to oil, gas, or sulphur under
terms of a lease.
(b) Federal agencies are exempt from the regulations in this part.
(c) G&G exploration or G&G scientific research related to minerals

[[Page 289]]

other than oil, gas, and sulphur is covered by regulations at 30 CFR
part 580.

Sec. Sec. 251.4-251.6 [Reserved]

Sec. 251.7 Test drilling activities under a permit.

(a) [Reserved]
(b) Deep stratigraphic tests. You must submit to the appropriate
BOEM or BSEE Regional Director, at the address in 30 CFR 551.5(d) for
BOEM or 30 CFR 254.7 for BSEE, a drilling plan (submitted to BOEM), an
environmental report (submitted to BOEM), an Application for Permit to
Drill (Form BSEE-0123) (submitted to BSEE), and a Supplemental APD
Information Sheet (Form BSEE-0123S) (submitted to BSEE) as follows:
(1) Drilling plan. The drilling plan must include:
(i) The proposed type, sequence, and timetable of drilling
activities;
(ii) A description of your drilling rig, indicating the important
features with special attention to safety, pollution prevention, oil-
spill containment and cleanup plans, and onshore disposal procedures;
(iii) The location of each deep stratigraphic test you will conduct,
including the location of the surface and projected bottomhole of the
borehole;
(iv) The types of geological and geophysical survey instruments you
will use before and during drilling;
(v) Seismic, bathymetric, sidescan sonar, magnetometer, or other
geophysical data and information sufficient to evaluate seafloor
characteristics, shallow geologic hazards, and structural detail across
and in the vicinity of the proposed test to the total depth of the
proposed test well; and
(vi) Other relevant data and information that the BOEM Regional
Director requires.
(2) Environmental report. The environmental report must include all
of the following material:
(i) A summary with data and information available at the time you
submitted the related drilling plan. BOEM will consider site-specific
data and information developed since the most recent environmental
impact statement or other environmental impact analysis in the immediate
area. The summary must meet the following requirements:
(A) You must concentrate on the issues specific to the site(s) of
drilling activity. However, you only need to summarize data and
information discussed in any environmental reports, analyses, or impact
statements prepared for the geographic area of the drilling activity.
(B) You must list referenced material. Include brief descriptions
and a statement of where the material is available for inspection.
(C) You must refer only to data that are available to BOEM.
(ii) Details about your project such as:
(A) A list and description of new or unusual technologies;
(B) The location of travel routes for supplies and personnel;
(C) The kinds and approximate levels of energy sources;
(D) The environmental monitoring systems; and
(E) Suitable maps and diagrams showing details of the proposed
project layout.
(iii) A description of the existing environment. For this section,
you must include the following information on the area:
(A) Geology;
(B) Physical oceanography;
(C) Other uses of the area;
(D) Flora and fauna;
(E) Existing environmental monitoring systems; and
(F) Other unusual or unique characteristics that may affect or be
affected by the drilling activities.
(iv) A description of the probable impacts of the proposed action on
the environment and the measures you propose for mitigating these
impacts.
(v) A description of any unavoidable or irreversible adverse effects
on the environment that could occur.
(vi) Other relevant data that the BOEM Regional Director requires.
(3) Copies for coastal States. You must submit copies of the
drilling plan and environmental report to the BOEM Regional Director for
transmittal to the Governor of each affected coastal State and the
coastal zone management agency of each affected coastal State that has
an approved program under

[[Page 290]]

the Coastal Zone Management Act. (The BOEM Regional Director will make
the drilling plan and environmental report available to appropriate
Federal agencies and the public according to the Department of the
Interior's policies and procedures).
(4) Certification of coastal zone management program consistency and
State concurrence. When required under an approved coastal zone
management program of an affected State, your drilling plan must include
a certification that the proposed activities described in the plan
comply with enforceable policies of, and will be conducted in a manner
consistent with such State's program. The BOEM Regional Director may not
approve any of the activities described in the drilling plan unless the
State concurs with the consistency certification or the Secretary of
Commerce makes the finding authorized by section 307(c)(3)(B)(iii) of
the Coastal Zone Management Act.
(5) Protecting archaeological resources. If the BOEM Regional
Director believes that an archaeological resource may exist in the area
that may be affected by drilling, the BOEM Regional Director will notify
you of the need to prepare an archaeological report under 30 CFR
551.7(b)(5).
(i) If the evidence suggests that an archaeological resource may be
present, you must:
(A) Locate the site of the drilling so as to not adversely affect
the area where the archaeological resources may be, or
(B) Establish to the satisfaction of the BOEM Regional Director that
an archaeological resource does not exist or will not be adversely
affected by drilling. This must be done by further archaeological
investigation, conducted by an archaeologist and a geophysicist, using
survey equipment and techniques deemed necessary by the Regional
Director. A report on the investigation must be submitted to the BOEM
Regional Director for review.
(ii) If the BOEM Regional Director determines that an archaeological
resource is likely to be present in the area that may be affected by
drilling, and may be adversely affected by drilling, the BOEM Regional
Director will notify you immediately. You must take no action that may
adversely affect the archaeological resource unless further
investigations determine that the resource is not archaeologically
significant.
(iii) If you discover any archaeological resource while drilling,
you must immediately halt drilling and report the discovery to the BOEM
Regional Director. If investigations determine that the resource is
significant, the BOEM Regional Director will inform you how to protect
it.
(6) Application for permit to drill (APD). Before commencing deep
stratigraphic test drilling activities under an approved drilling plan,
you must submit an APD and a Supplemental APD Information Sheet (Forms
BSEE-0123 and BSEE-0123S) and receive approval. You must comply with all
regulations relating to drilling operations in 30 CFR part 250.
(7) Revising an approved drilling plan. Before you revise an
approved drilling plan, you must obtain the BOEM Regional Director's
approval.
(8) After drilling. When you complete the test activities, you must
permanently plug and abandon the boreholes of all deep stratigraphic
tests in compliance with 30 CFR part 250. If the tract on which you
conducted a deep stratigraphic test is leased to another party for
exploration and development, and if the lessee has not disturbed the
borehole, BSEE will hold you and not the lessee responsible for problems
associated with the test hole.
(9) Deadline for completing a deep stratigraphic test. If your deep
stratigraphic test well is within 50 geographic miles of a tract that
BOEM has identified for a future lease sale, as listed on the currently
approved OCS leasing schedule, you must complete all drilling activities
and submit the data and information to the BOEM Regional Director at
least 60 days before the first day of the month in which BOEM schedules
the lease sale. However, the BOEM Regional Director may extend your
permit duration to allow you to complete drilling activities and submit
data and information if the extension is in the National interest.
(c)-(d) [Reserved]

[[Page 291]]

Sec. Sec. 251.8-251.14 [Reserved]

Sec. 251.15 Authority for information collection.

The Office of Management and Budget has approved the information
collection requirements in this part under 44 U.S.C. 3501 et seq. and
assigned OMB control number 1014-0025 as it pertains to Application for
Permit to Drill (APD, Form BSEE-0123), and Supplemental APD Information
Sheet (Form BSEE-0123S). The title of this information collection is
``30 CFR Part 250, Application for Permit to Drill (APD, Revised APD)
Supplemental APD Information Sheet, and all supporting documents.''

[81 FR 36151, June 6, 2016]

PART 252_OUTER CONTINENTAL SHELF (OCS) OIL AND GAS INFORMATION PROGRAM--
Table of Contents

Sec.
252.1 Purpose.
252.2 Definitions.
252.3 Oil and gas data and information to be provided for use in the OCS
Oil and Gas Information Program.
252.4 Summary Report to affected States.
252.5 Information to be made available to affected States.
252.6 Freedom of Information Act requirements.
252.7 Privileged and proprietary data and information to be made
available to affected States.

Authority: OCS Lands Act, 43 U.S.C. 1331 et seq., as amended, 92
Stat. 629; Freedom of Information Act, 5 U.S.C. 552; Sec. 252.3 also
issued under Pub. L. 99-190 making continuing appropriations for Fiscal
Year 1986, and for other purposes.

Source: 76 FR 64462, Oct. 18, 2011, unless otherwise noted.

Sec. 252.1 Purpose.

The purpose of this part is to implement the provisions of section
26 of the Act (43 U.S.C. 1352). This part supplements the procedures and
requirements contained in 30 CFR parts 250, 251, 550, and 551 and
provides procedures and requirements for the submission of oil and gas
data and information resulting from exploration, development, and
production operations on the Outer Continental Shelf (OCS) to the
Director, Bureau of Safety and Environmental Enforcement (BSEE). In
addition, this part establishes procedures for the Director to make
available certain information to the Governors of affected States and,
upon request, to the executives of affected local governments in
accordance with the provisions of the Freedom of Information Act and the
Act.

Sec. 252.2 Definitions.

When used in the regulations in this part, the following terms shall
have the following meanings:
Act refers to the Outer Continental Shelf Lands Act, as amended (43
U.S.C. 1331 et seq.).
Affected local government means the principal governing body of a
locality which is in an affected State and is identified by the Governor
of that State as a locality which will be significantly affected by oil
and gas activities on the OCS.
Affected State means, with respect to any program, plan, lease sale,
or other activity, proposed, conducted, or approved pursuant to the
provisions of the Act, any State:
(1) The laws of which are declared, pursuant to section 4(a)(2)(A)
of the Act, to be the law of the United States for the portion of the
OCS on which such activity is, or is proposed to be, conducted;
(2) Which is, or is proposed to be, directly connected by
transportation facilities to any artificial island or installations and
other devices permanently, or temporarily attached to the seabed;
(3) Which is receiving, or in accordance with the proposed activity
will receive, oil for processing, refining, or transshipment which was
extracted from the OCS and transported directly to such State by means
of vessels or by a combination of means including vessels;
(4) Which is designated by the Director as a State in which there is
a substantial probability of significant impact on or damage to the
coastal, marine, or human environment, or a State in which there will be
significant changes in the social, governmental, or economic
infrastructure, resulting from the exploration, development, and

[[Page 292]]

production of oil and gas anywhere on the OCS; or
(5) In which the Director finds that because of such activity there
is, or will be, a significant risk of serious damage, due to factors
such as prevailing winds and currents, to the marine or coastal
environment in the event of any oil spill, blowout, or release of oil or
gas from vessels, pipelines, or other transshipment facilities.
Analyzed geological information means data collected under a permit
or a lease which have been analyzed. Analysis may include, but is not
limited to, identification of lithologic and fossil content, core
analyses, laboratory analyses of physical and chemical properties, logs
or charts of electrical, radioactive, sonic, and other well logs, and
descriptions of hydrocarbon shows or hazardous conditions.
Area adjacent to a State means all of that portion of the OCS
included within a planning area if such planning area is bordered by
that State. The portion of the OCS in the Navarin Basin Planning Area is
deemed to be adjacent to the State of Alaska. The States of New York and
Rhode Island are deemed to be adjacent to both the Mid-Atlantic Planning
Area and the North Atlantic Planning Area.
Data means facts and statistics or samples which have not been
analyzed or processed.
Development means those activities which take place following
discovery of oil or natural gas in paying quantities, including
geophysical activity, drilling, platform construction, and operation of
all onshore support facilities, and which are for the purpose of
ultimately producing the oil and gas discovered.
Director means the Director of the Bureau of Safety and
Environmental Enforcement (BSEE) of the U.S. Department of the Interior
or a designee of the Director.
Exploration means the process of searching for oil and natural gas,
including:
(1) Geophysical surveys where magnetic, gravity, seismic, or other
systems are used to detect or imply the presence of such oil or natural
gas, and
(2) Any drilling, whether on or off known geological structures,
including the drilling of a well in which a discovery of oil or natural
gas in paying quantities is made and the drilling of any additional
delineation well after such discovery which is needed to delineate any
reservoir and to enable the lessee to determine whether to proceed with
development and production.
Governor means the Governor of a State, or the person or entity
designated by, or pursuant to, State law to exercise the powers granted
to a Governor pursuant to the Act.
Information, when used without a qualifying adjective, includes
analyzed geological information, processed geophysical information,
interpreted geological information, and interpreted geophysical
information.
Interpreted geological information means knowledge, often in the
form of schematic cross sections and maps, developed by determining the
geological significance of data and analyzed geological information.
Interpreted geophysical information means knowledge, often in the
form of schematic cross sections and maps, developed by determining the
geological significance of geophysical data and processed geophysical
information.
Lease means any form of authorization which is issued under section
8 or maintained under section 6 of the Act and which authorizes
exploration for, and development and production of, oil or natural gas,
or the land covered by such authorization, whichever is required by the
context.
Lessee means the party authorized by a lease, or an approved
assignment thereof, to explore for and develop and produce the leased
deposits in accordance with the regulations in 30 CFR part 550,
including all parties holding such authority by or through the lessee.
Outer Continental Shelf (OCS) means all submerged lands which lie
seaward and outside of the area of lands beneath navigable waters as
defined in the Submerged Lands Act (67 Stat. 29) and of which the
subsoil and seabed appertain to the United States and are subject to its
jurisdiction and control.
Permittee means the party authorized by a permit issued pursuant to
30 CFR parts 251 and 551 to conduct activities on the OCS.

[[Page 293]]

Processed geophysical information means data collected under a
permit or a lease which have been processed. Processing involves
changing the form of data so as to facilitate interpretation. Processing
operations may include, but are not limited to, applying corrections for
known perturbing causes, rearranging or filtering data, and combining or
transforming data elements.
Production means those activities which take place after the
successful completion of any means for the removal of oil or natural
gas, including such removal, field operations, transfer of oil or
natural gas to shore, operation monitoring, maintenance, and workover
drilling.
Secretary means the Secretary of the Interior or a designee of the
Secretary.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36151, June 6, 2016]

Sec. 252.3 Oil and gas data and information to be provided for use
in the OCS Oil and Gas Information Program.

(a) Any permittee or lessee engaging in the activities of
exploration for, or development and production of, oil and gas on the
OCS shall provide the Director access to all data and information
obtained or developed as a result of such activities, including
geological data, geophysical data, analyzed geological information,
processed and reprocessed geophysical information, interpreted
geophysical information, and interpreted geological information. Copies
of these data and information and any interpretation of these data and
information shall be provided to the Director upon request. No permittee
or lessee submitting an interpretation of data or information, where
such interpretation has been submitted in good faith, shall be held
responsible for any consequence of the use of or reliance upon such
interpretation.
(b)(1) Whenever a lessee or permittee provides any data or
information, at the request of the Director and specifically for use in
the OCS Oil and Gas Information Program in a form and manner of
processing which is utilized by the lessee or permittee in the normal
conduct of business, the Director shall pay the reasonable cost of
reproducing the data and information if the lessee or permittee requests
reimbursement. The cost shall be computed and paid in accordance with
the applicable provisions of paragraph (e)(1) of this section.
(2) Whenever a lessee or permittee provides any data or information,
at the request of the Director and specifically for use in the OCS Oil
and Gas Information Program, in a form and manner of processing not
normally utilized by the lessee or permittee in the normal conduct of
business, the Director shall pay the lessee or permittee, if the lessee
or permittee requests reimbursement, the reasonable cost of processing
and reproducing the requested data and information. The cost is to be
computed and paid in accordance with the applicable provisions of
paragraph (e)(2) of this section.
(c) Data or information requested by the Director shall be provided
as soon as practicable, but not later than 30 days following receipt of
the Director's request, unless, for good reason, the Director authorizes
a longer time period for the submission of the requested data or
information.
(d) The Director reserves the right to disclose any data or
information acquired from a lessee or permittee to an independent
contractor or agent for the purpose of reproducing, processing,
reprocessing, or interpreting such data or information. When
practicable, the Director shall notify the lessee(s) or permittee(s) who
provided the data or information of the intent to disclose the data or
information to an independent contractor or agent. The Director's notice
of intent will afford the permittee(s) or lessee(s) a period of not less
than 5 working days within which to comment on the intended action. When
the Director so notifies a lessee or permittee of the intent to disclose
data or information to an independent contractor or agent, all other
owners of such data or information shall be deemed to have been notified
of the Director's intent. Prior to any such disclosure, the contractor
or agent shall be required to execute a written commitment not to
disclose any data or information to anyone without the express consent
of the Director, and not to make any disclosure or use of the data or
information other than that

[[Page 294]]

provided in the contract. Contracts between BSEE and independent
contractors shall be available to the lessee(s) or permittee(s) for
inspection. In the event of any unauthorized use or disclosure of data
or information by the contractor or agent, or by an employee thereof,
the responsible contractor or agent or employee thereof shall be liable
for penalties pursuant to section 24 of the Act.
(e)(1) After delivery of data or information in accordance with
paragraph (b)(1) of this section and upon receipt of a request for
reimbursement and a determination by the Director that the requested
reimbursement is proper, the lessee or permittee shall be reimbursed for
the cost of reproducing the data or information at the lessee's or
permittee's lowest rate or at the lowest commercial rate established in
the area, whichever is less. Requests for reimbursement must be made
within 60 days of the delivery date of the data or information requested
under paragraph (b)(1) of this section.
(2) After delivery of data or information in accordance with
paragraph (b)(3) of this section, and upon receipt of a request for
reimbursement and a determination by the Director that the requested
reimbursement is proper, the lessee or permittee shall be reimbursed for
the cost of processing or reprocessing and of reproducing the requested
data or information. Requests for reimbursement must be made within 60
days of the delivery date of the data or information and shall be for
only the costs attributable to processing or reprocessing and
reproducing, as distinguished from the costs of data acquisition.
(3) Requests for reimbursement are to contain a breakdown of costs
in sufficient detail to allow separation of reproduction, processing,
and reprocessing costs from acquisition and other costs.
(f) Each Federal Department or Agency shall provide the Director
with any data which it has obtained pursuant to section 11 of the Act
and any other information which may be necessary or useful to assist the
Director in carrying out the provisions of the Act.

Sec. 252.4 Summary Report to affected States.

(a) The Director, as soon as practicable after analysis,
interpretation, and compilation of oil and gas data and information
developed by BSEE or furnished by lessees, permittees, or other
government agencies, shall make available to affected States and, upon
request, to the executive of any affected local government, a Summary
Report of data and information designed to assist them in planning for
the onshore impacts of potential OCS oil and gas development and
production. The Director shall consult with affected States and other
interested parties to define the nature, scope, content, and timing of
the Summary Report. The Director may consult with affected States and
other interested parties regarding subsequent revisions in the
definition of the nature, scope, content, and timing of the Summary
Report. The Summary Report shall not contain data or information which
the Director determines is exempt from disclosure in accordance with
this part. The Summary Report shall not contain data or information the
release of which the Director determines would unduly damage the
competitive position of the lessee or permittee who provided the data or
information which the Director has processed, analyzed, or interpreted
during the development of the Summary Report. The Summary Report shall
include:
(1) Estimates of oil and gas reserves; estimates of the oil and gas
resources that may be found within areas which the Secretary has leased
or plans to offer for lease; and when available, projected rates and
volumes of oil and gas to be produced from leased areas;
(2) Magnitude of the approximate projections and timing of
development, if and when oil or gas, or both, is discovered;
(3) Methods of transportation to be used, including vessels and
pipelines and approximate location of routes to be followed; and
(4) General location and nature of near-shore and onshore facilities
expected to be utilized.
(b) When the Director determines that significant changes have
occurred

[[Page 295]]

in the information contained in a Summary Report, the Director shall
prepare and make available the new or revised information to each
affected State, and, upon request, to the executive of any affected
local government.

Sec. 252.5 Information to be made available to affected States.

(a) The BOEM Director shall prepare an index of OCS information (see
30 CFR 556.10). The index shall list all relevant actual or proposed
programs, plans, reports, environmental impact statements, nominations
information, environmental study reports, lease sale information, and
any similar type of relevant information, including modifications,
comments, and revisions prepared or directly obtained by the Director
under the Act. The index shall be sent to affected States and, upon
request, to any affected local government. The public shall be informed
of the availability of the index.
(b) Upon request, the Director shall transmit to affected States,
affected local governments, and the public a copy of any information
listed in the index which is subject to the control of BOEM, in
accordance with the requirements and subject to the limitations of the
Freedom of Information Act (5 U.S.C.552) and implementing regulations.
The Director shall not transmit or make available any information which
he determines is exempt from disclosure in accordance with this part.

Sec. 252.6 Freedom of Information Act requirements.

(a) The Director shall make data and information available in
accordance with the requirements and subject to the limitations of the
Freedom of Information Act (5 U.S.C. 552), the regulations contained in
43 CFR part 2 (Records and Testimony), the requirements of the Act, and
the regulations contained in 30 CFR parts 250 and 550 (Oil and Gas and
Sulphur Operations in the Outer Continental Shelf) and 30 CFR parts 251
and 551 (Geological and Geophysical Explorations of the Outer
Continental Shelf).
(b) Except as provided in Sec. 252.7 or in 30 CFR parts 250, 251,
550, and 551, no data or information determined by the Director to be
exempt from public disclosure under paragraph (a) of this section shall
be provided to any affected State or be made available to the executive
of any affected local government or to the public unless the lessee, or
the permittee and all persons to whom such permittee has sold such data
or information under promise of confidentiality, agree to such action.

Sec. 252.7 Privileged and proprietary data and information
to be made available to affected States.

(a)(1) The Governor of any affected State may designate an
appropriate State official to inspect, at a regional location which the
Director shall designate, any privileged or proprietary data or
information received by the Director regarding any activity in an area
adjacent to such State, except that no such inspection shall take place
prior to the sale of a lease covering the area in which such activity
was conducted.
(2)(i) Except as provided for in 30 CFR 250.197, 30 CFR 550.197, and
30 CFR 551.14, no privileged or proprietary data or information will be
transmitted to any affected State unless the lessee who provided the
privileged or proprietary data or information agrees in writing to the
transmittal of the data or information.
(ii) Except as provided for in 30 CFR 250.197, 30 CFR 550.197, and
30 CFR 551.14, no privileged or proprietary data or information will be
transmitted to any affected State unless the permittee and all persons
to whom the permittee has sold the data or information under promise of
confidentiality agree in writing to the transmittal of the data or
information.
(3) Knowledge obtained by a State official who inspects data or
information under paragraph (a)(1) or who receives data or information
under paragraph (a)(2) of this section shall be subject to the
requirements and limitations of the Freedom of Information Act (5 U.S.C.
552), the regulations contained in 43 CFR part 2 (Records and
Testimony), the Act (92 Stat. 629), the regulations contained in 30 CFR
parts 250 and 550 (Oil and Gas and Sulphur Operations in the Outer
Continental Shelf), the regulations contained in 30 CFR

[[Page 296]]

parts 251 and 551 (Geological and Geophysical Explorations of the Outer
Continental Shelf), and the regulations contained in 30 CFR parts 252
and 552 (Outer Continental Shelf Oil and Gas Information Program).
(4) Prior to the transmittal of any privileged or proprietary data
or information to any State, or the grant of access to a State official
to such data or information, the Secretary shall enter into a written
agreement with the Governor of the State in accordance with section
26(e) of the Act (43 U.S.C. 1352). In that agreement the State shall
agree, as a condition precedent to receiving or being granted access to
such data or information to: (i) Protect and maintain the
confidentiality of privileged or proprietary data and information in
accordance with the laws and regulations listed in paragraph (a)(3) of
this section;
(ii) Waive the defenses as set forth in paragraph (b)(2) of this
section; and
(iii) Hold the United States harmless from any violations of the
agreement to protect the confidentiality of privileged or proprietary
data or information by the State or its employees or contractors.
(b)(1) Whenever any employee of the Federal Government or of any
State reveals in violation of the Act or of the provisions of the
regulations implementing the Act, privileged or proprietary data or
information obtained pursuant to the regulations in this chapter, the
lessee or permittee who supplied such information to the Director or any
other Federal official, and any person to whom such lessee or permittee
has sold such data or information under the promise of confidentiality,
may commence a civil action for damages in the appropriate district
court of the United States against the Federal Government or such State,
as the case may be. Any Federal or State employee who is found guilty of
failure to comply with any of the requirements of this section shall be
subject to the penalties described in section 24 of the Act (43 U.S.C.
1350).
(2) In any action commenced against the Federal Government or a
State pursuant to paragraph (b)(1) of this section, the Federal
Government or such State, as the case may be, may not raise as a defense
any claim of sovereign immunity, or any claim that the employee who
revealed the privileged or proprietary data or information which is the
basis of such suit was acting outside the scope of the person's
employment in revealing such data or information.
(c) If the Director finds that any State cannot or does not comply
with the conditions described in the agreement entered into pursuant to
paragraph (a)(4) of this section, the Director shall thereafter withhold
transmittal and deny access for inspection of privileged or proprietary
data or information to such State until the Director finds that such
State can and will comply with those conditions.

PART 253 [RESERVED]

PART 254_OIL-SPILL RESPONSE REQUIREMENTS FOR FACILITIES LOCATED SEAWARD
OF THE COAST LINE--Table of Contents

Subpart A_General

Sec.
254.1 Who must submit an oil spill response plan (OSRP)?
254.2 When must I submit an OSRP?
254.3 May I cover more than one facility in my OSRP?
254.4 May I reference other documents in my OSRP?
254.5 General response plan requirements.
254.6 Definitions.
254.7 How do I submit my OSRP to the BSEE?
254.8 May I appeal decisions under this part?
254.9 Authority for information collection.

Subpart B_Oil-Spill Response Plans for Outer Continental Shelf
Facilities

254.20 Purpose.
254.21 How must I format my OSRP?
254.22 What information must I include in the ``Introduction and OSRP
contents'' section?
254.23 What information must I include in the ``Emergency response
action plan'' section?
254.24 What information must I include in the ``Equipment inventory''
appendix?
254.25 What information must I include in the ``Contractual agreements''
appendix?
254.26 What information must I include in the ``Worst case discharge
scenario'' appendix?

[[Page 297]]

254.27 What information must I include in the ``Dispersant use plan''
appendix?
254.28 What information must I include in the ``In situ burning plan''
appendix?
254.29 What information must I include in the ``Training and drills''
appendix?
254.30 When must I revise my OSRP?

Subpart C_Related Requirements for Outer Continental Shelf Facilities

254.40 Records.
254.41 Training your response personnel.
254.42 Exercises for your response personnel and equipment.
254.43 Maintenance and periodic inspection of response equipment.
254.44 Calculating response equipment effective daily recovery
capacities.
254.45 Verifying the capabilities of your response equipment.
254.46 Whom do I notify if an oil spill occurs?
254.47 Determining the volume of oil of your worst case discharge
scenario.

Subpart D_Oil-Spill Response Requirements for Facilities Located in
State Waters Seaward of the Coast Line

254.50 Spill response plans for facilities located in State waters
seaward of the coast line.
254.51 Modifying an existing OCS OSRP.
254.52 Following the format for an OCS OSRP.
254.53 Submitting an OSRP developed under State requirements.
254.54 Spill prevention for facilities located in State waters seaward
of the coast line.
254.55 Spill response plans for facilities located in Alaska State
waters seaward of the coast line in the Chukchi and Beaufort
Seas.

Subpart E_Oil-Spill Response Requirements for Facilities Located on the
Arctic OCS

254.65 Purpose.
254.66-254.69 [Reserved]
254.70 What are the additional requirements for facilities conducting
exploratory drilling from a MODU on the Arctic OCS?
254.71-254.79 [Reserved]
254.80 What additional information must I include in the ``Emergency
response action plan'' section for facilities conducting
exploratory drilling from a MODU on the Arctic OCS?
254.81-254.89 [Reserved]
254.90 What are the additional requirements for exercises of your
response personnel and equipment for facilities conducting
exploratory drilling from a MODU on the Arctic OCS?

Authority: 33 U.S.C. 1321.

Source: 76 FR 64462, Oct. 18, 2011, unless otherwise noted.

Subpart A_General

Sec. 254.1 Who must submit an oil spill response plan (OSRP)?

(a) If you are the owner or operator of an oil handling, storage, or
transportation facility, and it is located seaward of the coast line,
you must submit an oil spill response plan (OSRP) to BSEE for approval.
Your OSRP must demonstrate that you can respond quickly and effectively
whenever oil is discharged from your facility. Refer to Sec. 254.6 for
the definitions of oil, facility, and coast line if you have any doubts
about whether to submit a plan.
(b) You must maintain a current OSRP for an abandoned facility until
you physically remove or dismantle the facility or until the Chief, Oil
Spill Preparedness Division (OSPD) notifies you in writing that a plan
is no longer required.
(c) Owners or operators of offshore pipelines carrying essentially
dry gas do not need to submit a plan. You must, however, submit a plan
for a pipeline that carries:
(1) Oil;
(2) Condensate that has been injected into the pipeline; or
(3) Gas and naturally occurring condensate.
(d) If you are in doubt as to whether you must submit a plan for an
offshore facility or pipeline, you should check with the Chief, OSPD.
(e) If your facility is located landward of the coast line, but you
believe your facility is sufficiently similar to OCS facilities that it
should be regulated by BSEE, you may contact the Chief, OSPD, offer to
accept BSEE jurisdiction over your facility, and request that BSEE seek
from the agency with jurisdiction over your facility a relinquishment of
that jurisdiction.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36151, June 6, 2016]

Sec. 254.2 When must I submit an OSRP?

(a) You must submit, and BSEE must approve, an OSRP that covers each
facility located seaward of the coast line before you may use that
facility. To continue operations, you must operate

[[Page 298]]

the facility in compliance with the OSRP.
(b) Despite the provisions of paragraph (a) of this section, you may
operate your facility after you submit your OSRP while BSEE reviews it
for approval. To operate a facility without an approved OSRP, you must
certify in writing to the Chief, OSPD that you have the capability to
respond, to the maximum extent practicable, to a worst case discharge or
a substantial threat of such a discharge. The certification must show
that you have ensured by contract, or other means approved by the Chief,
OSPD, the availability of private personnel and equipment necessary to
respond to the discharge. Verification from the organization(s)
providing the personnel and equipment must accompany the certification.
BSEE will not allow you to operate a facility for more than 2 years
without an approved OSRP.

[81 FR 36151, June 6, 2016]

Sec. 254.3 May I cover more than one facility in my OSRP?

(a) Your OSRP may be for a single lease or facility or a group of
leases or facilities. All the leases or facilities in your plan must
have the same owner or operator (including affiliates) and must be
located in the same BSEE Region (see definition of Regional OSRP in
Sec. 254.6).
(b) Regional OSRPs must address all the elements required for an
OSRP in subpart B, or subpart D of this part, as appropriate.
(c) When developing a Regional OSRP, you may group leases or
facilities subject to the approval of the Chief, OSPD, for the purposes
of:
(1) Calculating response times;
(2) Determining quantities of response equipment;
(3) Conducting oil-spill trajectory analyses;
(4) Determining worst case discharge scenarios; and
(5) Identifying areas of special economic and environmental
importance that may be impacted and the strategies for their protection.
(d) The Chief, OSPD, may specify how to address the elements of a
Regional OSRP. The Chief, OSPD, also may require that Regional OSRPs
contain additional information if necessary for compliance with
appropriate laws and regulations.

[81 FR 36151, June 6, 2016]

Sec. 254.4 May I reference other documents in my OSRP?

You may reference information contained in other readily accessible
documents in your OSRP. Examples of documents that you may reference are
the National Contingency Plan (NCP), Area Contingency Plan (ACP), BSEE
or BOEM environmental documents, and Oil Spill Removal Organization
(OSRO) documents that are readily accessible to the Chief, OSPD. You
must ensure that the Chief, OSPD, possesses or is provided with copies
of all OSRO documents you reference. You should contact the Chief, OSPD,
if you want to know whether a reference is acceptable.

[81 FR 36152, June 6, 2016]

Sec. 254.5 General response plan requirements.

(a) The OSRP must provide for response to an oil spill from the
facility. You must immediately carry out the provisions of the OSRP
whenever there is a release of oil from the facility. You must also
carry out the training, equipment testing, and periodic drills described
in the OSRP, and these measures must be sufficient to ensure the safety
of the facility and to mitigate or prevent a discharge or a substantial
threat of a discharge.
(b) The OSRP must be consistent with the National Contingency Plan
and the appropriate Area Contingency Plan(s).
(c) Nothing in this part relieves you from taking all appropriate
actions necessary to immediately abate the source of a spill and remove
any spills of oil.
(d) In addition to the requirements listed in this part, you must
provide any other information the Chief, OSPD, requires for compliance
with appropriate laws and regulations.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36152, June 6, 2016]

Sec. 254.6 Definitions.

For the purposes of this part:

[[Page 299]]

Adverse weather conditions means, for the purposes of this part,
weather conditions found in the operating area that make it difficult
for response equipment and personnel to clean up or remove spilled oil
or hazardous substances. These conditions include, but are not limited
to: fog, inhospitable water and air temperatures, wind, sea ice, extreme
cold, freezing spray, snow, currents, sea states, and extended periods
of low light. Adverse weather conditions do not refer to conditions
under which it would be dangerous or impossible to respond to a spill,
such as a hurricane.
Arctic OCS means the Beaufort Sea and Chukchi Sea Planning Areas
(for more information on these areas, see the Proposed Final OCS Oil and
Gas Leasing Program for 2012-2017 (June 2012) at http://www.boem.gov/
Oil-and-Gas-Energy-Program/Leasing/ Five-Year-Program/2012-2017/Program-
Area-Maps/index.aspx).
Area Contingency Plan means an Area Contingency Plan prepared and
published under section 311(j) of the Federal Water Pollution Control
Act (FWPCA).
Chief, OSPD means the Chief, BSEE Oil Spill Preparedness Division or
designee.
Coast line means the line of ordinary low water along that portion
of the coast which is in direct contact with the open sea and the line
marking the seaward limit of inland waters.
Discharge means any emission (other than natural seepage),
intentional or unintentional, and includes, but is not limited to,
spilling, leaking, pumping, pouring, emitting, emptying, or dumping.
District Manager means the BSEE officer with authority and
responsibility for a district within a BSEE Region.
Facility means any structure, group of structures, equipment, or
device (other than a vessel) which is used for one or more of the
following purposes: Exploring for, drilling for, producing, storing,
handling, transferring, processing, or transporting oil. The term
excludes deep-water ports and their associated pipelines as defined by
the Deepwater Port Act of 1974, but includes other pipelines used for
one or more of these purposes. A mobile offshore drilling unit is
classified as a facility when engaged in drilling or downhole
operations.
Ice intervention practices mean the equipment, vessels, and
procedures used to increase oil encounter rates and the effectiveness of
spill response techniques and equipment when sea ice is present.
Maximum extent practicable means within the limitations of available
technology, as well as the physical limitations of personnel, when
responding to a worst case discharge in adverse weather conditions.
National Contingency Plan means the National Oil and Hazardous
Substances Pollution Contingency Plan prepared and published under
section 311(d) of the FWPCA, (33 U.S.C. 1321(d)) or revised under
section 105 of the Comprehensive Environmental Response Compensation and
Liability Act (42 U.S.C. 9605).
National Contingency Plan Product Schedule means a schedule of
dispersants and other chemical or biological products, maintained by the
Environmental Protection Agency, that may be authorized for use on oil
discharges in accordance with the procedures found at 40 CFR 300.910.
Oil means oil of any kind or in any form, including but not limited
to petroleum, fuel oil, sludge, oil refuse, and oil mixed with wastes
other than dredged spoil. This also includes hydrocarbons produced at
the wellhead in liquid form (includes distillates or condensate
associated with produced natural gas), and condensate that has been
separated from a gas prior to injection into a pipeline. It does not
include petroleum, including crude oil or any fraction thereof, which is
specifically listed or designated as a hazardous substance under
paragraphs (A) through (F) of section 101(14) of the Comprehensive
Environmental Response, Compensation, and Liability Act (42 U.S.C. 9601)
and which is subject to the provisions of that Act. It also does not
include animal fats and oils and greases and fish and marine mammal
oils, within the meaning of paragraph (2) of section 61(a) of title 13,
United States Code, and oils of vegetable origin, including oils from
the seeds, nuts, and

[[Page 300]]

kernels referred to in paragraph (1)(A) of that section.
Oil spill removal organization (OSRO) means an entity contracted by
an owner or operator to provide spill-response equipment and/or manpower
in the event of an oil or hazardous substance spill.
OSRP means an Oil Spill Response Plan.
Outer Continental Shelf means all submerged lands lying seaward and
outside of the area of lands beneath navigable waters as defined in
section 2 of the Submerged Lands Act (43 U.S.C. 1301) and of which the
subsoil and seabed appertain to the United States and are subject to its
jurisdiction and control.
Owner or operator means, in the case of an offshore facility, any
person owning or operating such offshore facility. In the case of any
abandoned offshore facility, it means the person who owned such facility
immediately prior to such abandonment.
Pipeline means pipe and any associated equipment, appurtenance, or
building used or intended for use in the transportation of oil located
seaward of the coast line, except those used for deep-water ports.
Pipelines do not include vessels such as barges or shuttle tankers used
to transport oil from facilities located seaward of the coast line.
Qualified individual means an English-speaking representative of an
owner or operator, located in the United States, available on a 24-hour
basis, with full authority to obligate funds, carry out removal actions,
and communicate with the appropriate Federal officials and the persons
providing personnel and equipment in removal operations.
Regional Response Plan means a spill-response plan required by this
part which covers multiple facilities or leases of an owner or operator,
including affiliates, which are located in the same BSEE Region.
Regional Supervisor means the BSEE official with responsibility and
authority for operations or other designated program functions within a
BSEE Region.
Remove means containment and cleanup of oil from water and
shorelines or the taking of other actions as may be necessary to
minimize or mitigate damage to the public health or welfare, including,
but not limited to, fish, shellfish, wildlife, public and private
property, shorelines, and beaches.
Spill is synonymous with ``discharge'' for the purposes of this
part.
Spill management team means the trained persons identified in an
OSRP who staff the organizational structure to manage spill response.
Spill-response coordinator means a trained person charged with the
responsibility and designated the commensurate authority for directing
and coordinating response operations.
Spill-response operating team means the trained persons who respond
to spills through deployment and operation of oil-spill response
equipment.
State waters located seaward of the coast line means the belt of the
seas measured from the coast line and extending seaward a distance of 3
miles (except the coast of Texas and the Gulf coast of Florida, where
the State waters extend seaward a distance of 3 leagues).
You means the owner or the operator as defined in this section.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36152, June 6, 2016; 81
FR 46563, July 15, 2016]

Sec. 254.7 How do I submit my OSRP to the BSEE?

You must submit the number of copies of your OSRP that the
appropriate BSEE regional office requires. If you prefer to use improved
information technology such as electronic filing to submit your plan,
ask the Chief, OSPD, for further guidance.
(a) Send OSRPs for facilities located seaward of the coast line of
Alaska to: Bureau of Safety and Environmental Enforcement, Oil Spill
Preparedness Division, Attention: Senior Analyst, 3801 Centerpoint
Drive, Suite 500, Anchorage, AK 99503-5823.
(b) Send OSRPs for facilities in the Gulf of Mexico or Atlantic
Ocean to: Bureau of Safety and Environmental Enforcement, Oil Spill
Preparedness Division, Attention: GOM Section Supervisor, 1201 Elmwood
Park Boulevard, New Orleans, LA 70123-2394.

[[Page 301]]

(c) Send OSRPs for facilities in the Pacific Ocean (except seaward
of the coast line of Alaska) to: Bureau of Safety and Environmental
Enforcement, Oil Spill Preparedness Division, Attention: Senior Analyst,
760 Paseo Camarillo, Suite 201, Camarillo, CA 93010-6002.

[81 FR 36152, June 6, 2016]

Sec. 254.8 May I appeal decisions under this part?

See 30 CFR part 290 for instructions on how to appeal any order or
decision that we issue under this part.

Sec. 254.9 Authority for information collection.

(a) The Office of Management and Budget (OMB) has approved the
information collection requirements in this part under 44 U.S.C. 3501 et
seq. OMB assigned the control number 1014-0007. The title of this
information collection is ``30 CFR part 254, Oil Spill Response
Requirements for Facilities Located Seaward of the Coast line.''
(b) BSEE collects this information to ensure that the owner or
operator of an offshore facility is prepared to respond to an oil spill.
BSEE uses the information to verify compliance with the mandates of the
Oil Pollution Act of 1990 (OPA). The requirement to submit this
information is mandatory. No confidential or proprietary information is
collected.
(c) An agency may not conduct or sponsor, and a person is not
required to respond to, a collection of information unless it displays a
currently valid OMB control number.
(d) Send comments regarding any aspect of the collection of
information under this part, including suggestions for reducing the
burden, to the Information Collection Clearance Officer, Bureau of
Safety and Environmental Enforcement, 45600 Woodland Road, Sterling, VA
20166.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36152, June 6, 2016]

Subpart B_Oil-Spill Response Plans for Outer Continental Shelf
Facilities

Sec. 254.20 Purpose.

This subpart describes the requirements for preparing OSRPs for
facilities located on the OCS.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36152, June 6, 2016]

Sec. 254.21 How must I format my OSRP?

(a) You must divide your OSRP for OCS facilities into the sections
specified in paragraph (b) of this section and explained in the other
sections of this subpart. The OSRP must have an easily found marker
identifying each section. You may use an alternate format if you include
a cross reference table to identify the location of required sections.
You may use alternate contents if you can demonstrate to the Chief, OSPD
that they provide for equal or greater levels of preparedness.
(b) Your OSRP must include:
(1) Introduction and OSRP contents.
(2) Emergency response action plan.
(3) Appendices:
(i) Equipment inventory.
(ii) Contractual agreements.
(iii) Worst case discharge scenario.
(iv) Dispersant use plan.
(v) In situ burning plan.
(vi) Training and drills.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36152, June 6, 2016]

Sec. 254.22 What information must I include in the
``Introduction and OSRP contents'' section?

The ``Introduction and OSRP contents'' section must provide:
(a) Identification of the facility the OSRP covers, including its
location and type;
(b) A table of contents;
(c) A record of changes made to the OSRP; and
(d) A cross-reference table, if needed, because you are using an
alternate format for your OSRP.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36152, June 6, 2016]

[[Page 302]]

Sec. 254.23 What information must I include in the
``Emergency response action plan'' section?

The ``Emergency response action plan'' section is the core of the
OSRP. Put information in easy-to-use formats such as flow charts or
tables where appropriate. This section must include:
(a) Designation, by name or position, of a trained qualified
individual (QI) who has full authority to implement removal actions and
ensure immediate notification of appropriate Federal officials and
response personnel.
(b) Designation, by name or position, of a trained spill management
team available on a 24-hour basis. The team must include a trained
spill-response coordinator and alternate(s) who have the responsibility
and authority to direct and coordinate response operations on your
behalf. You must describe the team's organizational structure as well as
the responsibilities and authorities of each position on the spill
management team.
(c) Description of a spill-response operating team. Team members
must be trained and available on a 24-hour basis to deploy and operate
spill-response equipment. They must be able to respond within a
reasonable minimum specified time. You must include the number and types
of personnel available from each identified labor source.
(d) A planned location for a spill-response operations center and
provisions for primary and alternate communications systems available
for use in coordinating and directing spill-response operations. You
must provide telephone numbers for the response operations center. You
also must provide any facsimile numbers and primary and secondary radio
frequencies that will be used.
(e) A listing of the types and characteristics of the oil handled,
stored, or transported at the facility.
(f) Procedures for the early detection of a spill.
(g) Identification of procedures you will follow in the event of a
spill or a substantial threat of a spill. The procedures should show
appropriate response levels for differing spill sizes including those
resulting from a fire or explosion. These will include, as appropriate:
(1) Your procedures for spill notification. The plan must provide
for the use of the oil spill reporting forms included in the Area
Contingency Plan or an equivalent reporting form.
(i) Your procedures must include a current list which identifies the
following by name or position, corporate address, and telephone number
(including facsimile number if applicable):
(A) The qualified individual;
(B) The spill-response coordinator and alternate(s); and
(C) Other spill-response management team members.
(ii) You must also provide names, telephone numbers, and addresses
for the following:
(A) OSRO's that the plan cites;
(B) Federal, State, and local regulatory agencies that you must
consult to obtain site specific environmental information; and
(C) Federal, State, and local regulatory agencies that you must
notify when an oil spill occurs.
(2) Your methods to monitor and predict spill movement;
(3) Your methods to identify and prioritize the beaches, waterfowl,
other marine and shoreline resources, and areas of special economic and
environmental importance;
(4) Your methods to protect beaches, waterfowl, other marine and
shoreline resources, and areas of special economic or environmental
importance;
(5) Your methods to ensure that containment and recovery equipment
as well as the response personnel are mobilized and deployed at the
spill site;
(6) Your methods to ensure that devices for the storage of recovered
oil are sufficient to allow containment and recovery operations to
continue without interruption;
(7) Your procedures to remove oil and oiled debris from shallow
waters and along shorelines and rehabilitating waterfowl which become
oiled;
(8) Your procedures to store, transfer, and dispose of recovered oil
and oil-contaminated materials and to ensure that all disposal is in
accordance with Federal, State, and local requirements; and

[[Page 303]]

(9) Your methods to implement your dispersant use plan and your in
situ burning plan.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36152, June 6, 2016]

Sec. 254.24 What information must I include in the
``Equipment inventory'' appendix?

Your ``Equipment inventory appendix'' must include:
(a) An inventory of spill-response materials and supplies, services,
equipment, and response vessels available locally and regionally. You
must identify each supplier and provide their locations and telephone
numbers.
(b) A description of the procedures for inspecting and maintaining
spill-response equipment in accordance with Sec. 254.43.

Sec. 254.25 What information must I include in the
``Contractual agreements'' appendix?

Your ``Contractual agreements'' appendix must furnish proof of any
contracts or membership agreements with OSRO's, cooperatives, spill-
response service providers, or spill management team members who are not
your employees that you cite in the OSRP. To provide this proof, submit
copies of the contracts or membership agreements or certify that
contracts or membership agreements are in effect. The contract or
membership agreement must include provisions for ensuring the
availability of the personnel and/or equipment on a 24-hour-per-day
basis.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36152, June 6, 2016]

Sec. 254.26 What information must I include in the
``Worst case discharge scenario'' appendix?

The discussion of your worst case discharge scenario must include
all of the following elements:
(a) The volume of your worst case discharge scenario determined
using the criteria in Sec. 254.47. Provide any assumptions made and the
supporting calculations used to determine this volume.
(b) An appropriate trajectory analysis specific to the area in which
the facility is located. The analysis must identify onshore and offshore
areas that a discharge potentially could affect. The trajectory analysis
chosen must reflect the maximum distance from the facility that oil
could move in a time period that it reasonably could be expected to
persist in the environment.
(c) A list of the resources of special economic or environmental
importance that potentially could be impacted in the areas identified by
your trajectory analysis. You also must state the strategies that you
will use for their protection. At a minimum, this list must include
those resources of special economic and environmental importance, if
any, specified in the appropriate Area Contingency Plan(s).
(d) A discussion of your response to your worst case discharge
scenario in adverse weather conditions. This discussion must include:
(1) A description of the response equipment that you will use to
contain and recover the discharge to the maximum extent practicable.
This description must include the types, location(s) and owner,
quantity, and capabilities of the equipment. You also must include the
effective daily recovery capacities, where applicable. You must
calculate the effective daily recovery capacities using the methods
described in Sec. 254.44. For operations at a drilling or production
facility, your scenario must show how you will cope with the initial
spill volume upon arrival at the scene and then support operations for a
blowout lasting 30 days.
(2) A description of the personnel, materials, and support vessels
that would be necessary to ensure that the identified response equipment
is deployed and operated promptly and effectively. Your description must
include the location and owner of these resources as well as the
quantities and types (if applicable);
(3) A description of your oil storage, transfer, and disposal
equipment. Your description must include the types, location and owner,
quantity, and capacities of the equipment; and
(4) An estimation of the individual times needed for:
(i) Procurement of the identified containment, recovery, and storage
equipment;

[[Page 304]]

(ii) Procurement of equipment transportation vessel(s);
(iii) Procurement of personnel to load and operate the equipment;
(iv) Equipment loadout (transfer of equipment to transportation
vessel(s));
(v) Travel to the deployment site (including any time required for
travel from an equipment storage area); and
(vi) Equipment deployment.
(e) In preparing the discussion required by paragraph (d) of this
section, you must:
(1) Ensure that the response equipment, materials, support vessels,
and strategies listed are suitable, within the limits of current
technology, for the range of environmental conditions anticipated at
your facility; and
(2) Use standardized, defined terms to describe the range of
environmental conditions anticipated and the capabilities of response
equipment. Examples of acceptable terms include those defined in
American Society for Testing of Materials (ASTM) publication F625-94,
Standard Practice for Describing Environmental Conditions Relevant to
Spill Control Systems for Use on Water, and ASTM F818-93, Standard
Definitions Relating to Spill Response Barriers.

Sec. 254.27 What information must I include in the
``Dispersant use plan'' appendix?

Your dispersant use plan must be consistent with the National
Contingency Plan Product Schedule and other provisions of the National
Contingency Plan and the appropriate Area Contingency Plan(s). The plan
must include:
(a) An inventory and a location of the dispersants and other
chemical or biological products which you might use on the oils handled,
stored, or transported at the facility;
(b) A summary of toxicity data for these products;
(c) A description and a location of any application equipment
required as well as an estimate of the time to commence application
after approval is obtained;
(d) A discussion of the application procedures;
(e) A discussion of the conditions under which product use may be
requested; and
(f) An outline of the procedures you must follow in obtaining
approval for product use.

Sec. 254.28 What information must I include in the
``In situ burning plan'' appendix?

Your in situ burning plan must be consistent with any guidelines
authorized by the National Contingency Plan and the appropriate Area
Contingency Plan(s). Your in situ burning plan must include:
(a) A description of the in situ burn equipment including its
availability, location, and owner;
(b) A discussion of your in situ burning procedures, including
provisions for ignition of an oil spill;
(c) A discussion of environmental effects of an in situ burn;
(d) Your guidelines for well control and safety of personnel and
property;
(e) A discussion of the circumstances in which in situ burning may
be appropriate;
(f) Your guidelines for making the decision to ignite; and
(g) An outline of the procedures you must follow to obtain approval
for an in situ burn.

Sec. 254.29 What information must I include in the
``Training and drills'' appendix?

Your ``Training and drills'' appendix must:
(a) Identify and include the dates of the training provided to
members of the spill-response management team and the qualified
individual. The types of training given to the members of the spill-
response operating team also must be described. The training
requirements for your spill management team and your spill-response
operating team are specified in Sec. 254.41. You must designate a
location where you keep course completion certificates or attendance
records for this training.
(b) Describe in detail your plans for satisfying the exercise
requirements of Sec. 254.42. You must designate a location where you
keep the records of these exercises.

[[Page 305]]

Sec. 254.30 When must I revise my OSRP?

(a) You must review your OSRP at least every 2 years and submit all
resulting modifications to the Chief, OSPD. If this review does not
result in modifications, you must inform the Chief, OSPD, in writing
that there are no changes.
(b) You must submit revisions to your OSRP for approval within 15
days whenever:
(1) A change occurs which significantly reduces your response
capabilities;
(2) A significant change occurs in the worst case discharge scenario
or in the type of oil being handled, stored, or transported at the
facility;
(3) There is a change in the name(s) or capabilities of the oil
spill removal organizations cited in the OSRP; or
(4) There is a significant change to the Area Contingency Plan(s).
(c) The Chief, OSPD, may require that you resubmit your OSRP if the
OSRP has become outdated or if numerous revisions have made its use
difficult.
(d) The Chief, OSPD, will periodically review the equipment
inventories of OSRO's to ensure that sufficient spill removal equipment
is available to meet the cumulative needs of the owners and operators
who cite these organizations in their OSRPs.
(e) The Chief, OSPD, may require you to revise your OSRP if
significant inadequacies are indicated by:
(1) Periodic reviews (described in paragraph (d) of this section);
(2) Information obtained during drills or actual spill responses; or
(3) Other relevant information the Chief, OSPD, obtained.

[81 FR 36152, June 6, 2016]

Subpart C_Related Requirements for Outer Continental Shelf Facilities

Sec. 254.40 Records.

You must make all records of services, personnel, and equipment
provided by OSRO's or cooperatives available to any authorized BSEE
representative upon request.

Sec. 254.41 Training your response personnel.

(a) You must ensure that the members of your spill-response
operating team who are responsible for operating response equipment
attend hands-on training classes at least annually. This training must
include the deployment and operation of the response equipment they will
use. Those responsible for supervising the team must be trained annually
in directing the deployment and use of the response equipment.
(b) You must ensure that the spill-response management team,
including the spill-response coordinator and alternates, receives annual
training. This training must include instruction on:
(1) Locations, intended use, deployment strategies, and the
operational and logistical requirements of response equipment;
(2) Spill reporting procedures;
(3) Oil-spill trajectory analysis and predicting spill movement; and
(4) Any other responsibilities the spill management team may have.
(c) You must ensure that the qualified individual is sufficiently
trained to perform his or her duties.
(d) You must keep all training certificates and training attendance
records at the location designated in your OSRP for at least 2 years.
They must be made available to any authorized BSEE representative upon
request.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36153, June 6, 2016]

Sec. 254.42 Exercises for your response personnel and equipment.

(a) You must exercise your entire OSRP at least once every 3 years
(triennial exercise). You may satisfy this requirement by conducting
separate exercises for individual parts of the OSRP over the 3-year
period; you do not have to exercise your entire OSRP at one time.
(b) In satisfying the triennial exercise requirement, you must, at a
minimum, conduct:
(1) An annual spill management team tabletop exercise. The exercise
must test the spill management team's organization, communication, and
decision making in managing a response. You must not reveal the spill
scenario to

[[Page 306]]

team members before the exercise starts.
(2) An annual deployment exercise of response equipment identified
in your OSRP that is staged at onshore locations. You must deploy and
operate each type of equipment in each triennial period. However, it is
not necessary to deploy and operate each individual piece of equipment.
(3) An annual notification exercise for each facility that is manned
on a 24- hour basis. The exercise must test the ability of facility
personnel to communicate pertinent information in a timely manner to the
qualified individual.
(4) A semiannual deployment exercise of any response equipment which
the BSEE Regional Supervisor requires an owner or operator to maintain
at the facility or on dedicated vessels. You must deploy and operate
each type of this equipment at least once each year. Each type need not
be deployed and operated at each exercise.
(c) During your exercises, you must simulate conditions in the area
of operations, including seasonal weather variations, to the extent
practicable. The exercises must cover a range of scenarios over the 3-
year exercise period, simulating responses to large continuous spills,
spills of short duration and limited volume, and your worst case
discharge scenario.
(d) BSEE will recognize and give credit for any documented exercise
conducted that satisfies some part of the required triennial exercise.
You will receive this credit whether the owner or operator, an OSRO, or
a Government regulatory agency initiates the exercise. BSEE will give
you credit for an actual spill response if you evaluate the response and
generate a proper record. Exercise documentation should include the
following information:
(1) Type of exercise;
(2) Date and time of the exercise;
(3) Description of the exercise;
(4) Objectives met; and
(5) Lessons learned.
(e) All records of spill-response exercises must be maintained for
the complete 3-year exercise cycle. Records should be maintained at the
facility or at a corporate location designated in the OSRP. Records
showing that OSROs and oil spill removal cooperatives have deployed each
type of equipment also must be maintained for the 3-year cycle.
(f) You must inform the Chief, OSPD of the date of any exercise
required by paragraph (b)(1), (2), or (4) of this section at least 30
days before the exercise. This will allow BSEE personnel the opportunity
to witness any exercises.
(g) The Regional Supervisor periodically will initiate unannounced
drills to test the spill response preparedness of owners and operators.
(h) The Chief, OSPD may require changes in the frequency or location
of the required exercises, equipment to be deployed and operated, or
deployment procedures or strategies. The Chief, OSPD may evaluate the
results of the exercises and advise the owner or operator of any needed
changes in response equipment, procedures, or strategies.
(i) Compliance with the National Preparedness for Response Exercise
Program (PREP) Guidelines will satisfy the exercise requirements of this
section. Copies of the PREP document may be obtained from the Chief,
OSPD.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36153, June 6, 2016]

Sec. 254.43 Maintenance and periodic inspection of response equipment.

(a) You must ensure that the response equipment listed in your OSRP
is inspected at least monthly and is maintained, as necessary, to ensure
optimal performance.
(b) You must ensure that records of the inspections and the
maintenance activities are kept for at least 2 years and are made
available to any authorized BSEE representative upon request.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36153, June 6, 2016]

Sec. 254.44 Calculating response equipment effective
daily recovery capacities.

(a) You are required by Sec. 254.26(d)(1) to calculate the
effective daily recovery capacity of the response equipment identified
in your OSRP that you would use to contain and recover your

[[Page 307]]

worst case discharge. You must calculate the effective daily recovery
capacity of the equipment by multiplying the manufacturer's rated
throughput capacity over a 24-hour period by 20 percent. This 20 percent
efficiency factor takes into account the limitations of the recovery
operations due to available daylight, sea state, temperature, viscosity,
and emulsification of the oil being recovered. You must use this
calculated rate to determine if you have sufficient recovery capacity to
respond to your worst case discharge scenario.
(b) If you want to use a different efficiency factor for specific
oil recovery devices, you must submit evidence to substantiate that
efficiency factor. Adequate evidence includes verified performance data
measured during actual spills or test data gathered according to the
provisions of Sec. 254.45(b) and (c).

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36153, June 6, 2016]

Sec. 254.45 Verifying the capabilities of your response equipment.

(a) The Regional Supervisor may require performance testing of any
spill-response equipment listed in your OSRP to verify its capabilities
if the equipment:
(1) Has been modified;
(2) Has been damaged and repaired; or
(3) Has a claimed effective daily recovery capacity that is
inconsistent with data otherwise available to BSEE.
(b) You must conduct any required performance testing of booms in
accordance with BSEE-approved test criteria. You may use the document
``Test Protocol for the Evaluation of Oil-Spill Containment Booms,''
available from BSEE, for guidance. Performance testing of skimmers also
must be conducted in accordance with BSEE approved test criteria. You
may use the document ``Suggested Test Protocol for the Evaluation of Oil
Spill Skimmers for the OCS,'' available from BSEE, for guidance.
(c) You are responsible for any required testing of equipment
performance and for the accuracy of the information submitted.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36153, June 6, 2016]

Sec. 254.46 Whom do I notify if an oil spill occurs?

(a) You must immediately notify the National Response Center (1-800-
424-8802) if you observe:
(1) An oil spill from your facility;
(2) An oil spill from another offshore facility; or
(3) An offshore spill of unknown origin.
(b) In the event of a spill of 1 barrel or more from your facility,
you must orally notify the Regional Supervisor without delay. You also
must report spills from your facility of unknown size but thought to be
1 barrel or more.
(1) If a spill from your facility not originally reported to the
Regional Supervisor is subsequently found to be 1 barrel or more, you
must then report it without delay.
(2) You must file a written follow up report for any spill from your
facility of 1 barrel or more. The Chief, OSPD must receive this
confirmation within 15 days after the spillage has been stopped. All
reports must include the cause, location, volume, and remedial action
taken. Reports of spills of more than 50 barrels must include
information on the sea state, meteorological conditions, and the size
and appearance of the slick. The Regional Supervisor may require
additional information if it is determined that an analysis of the
response is necessary.
(c) If you observe a spill resulting from operations at another
offshore facility, you must immediately notify the responsible party and
the Regional Supervisor.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36153, June 6, 2016]

Sec. 254.47 Determining the volume of oil of your
worst case discharge scenario.

You must calculate the volume of oil of your worst case discharge
scenario as follows:
(a) For an oil production platform facility, the size of your worst
case discharge scenario is the sum of the following:
(1) The maximum capacity of all oil storage tanks and flow lines on
the facility. Flow line volume may be estimated; and

[[Page 308]]

(2) The volume of oil calculated to leak from a break in any
pipelines connected to the facility considering shutdown time, the
effect of hydrostatic pressure, gravity, frictional wall forces and
other factors; and
(3) The daily production volume from an uncontrolled blowout of the
highest capacity well associated with the facility. In determining the
daily discharge rate, you must consider reservoir characteristics,
casing/production tubing sizes, and historical production and reservoir
pressure data. Your scenario must discuss how to respond to this well
flowing for 30 days as required by Sec. 254.26(d)(1).
(b) For exploratory or development drilling operations, the size of
your worst case discharge scenario is the daily volume possible from an
uncontrolled blowout. In determining the daily discharge rate, you must
consider any known reservoir characteristics. If reservoir
characteristics are unknown, you must consider the characteristics of
any analog reservoirs from the area and give an explanation for the
selection of the reservoir(s) used. Your scenario must discuss how to
respond to this well flowing for 30 days as required by Sec.
254.26(d)(1).
(c) For a pipeline facility, the size of your worst case discharge
scenario is the volume possible from a pipeline break. You must
calculate this volume as follows:
(1) Add the pipeline system leak detection time to the shutdown
response time.
(2) Multiply the time calculated in paragraph (c)(1) of this section
by the highest measured oil flow rate over the preceding 12-month
period. For new pipelines, you should use the predicted oil flow rate in
the calculation.
(3) Add to the volume calculated in paragraph (c)(2) of this section
the total volume of oil that would leak from the pipeline after it is
shut in. Calculate this volume by taking into account the effects of
hydrostatic pressure, gravity, frictional wall forces, length of
pipeline segment, tie-ins with other pipelines, and other factors.
(d) If your facility which stores, handles, transfers, processes, or
transports oil does not fall into the categories listed in paragraph
(a), (b), or (c) of this section, contact the Chief, OSPD for
instructions on the calculation of the volume of your worst case
discharge scenario.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36153, June 6, 2016]

Subpart D_Oil-Spill Response Requirements for Facilities Located in
State Waters Seaward of the Coast Line

Sec. 254.50 Spill response plans for facilities located in State waters
seaward of the coast line.

Owners or operators of facilities located in State waters seaward of
the coast line must submit a spill-response plan to BSEE for approval.
You may choose one of three methods to comply with this requirement. The
three methods are described in Sec. Sec. 254.51, 254.52, and 254.53.

Sec. 254.51 Modifying an existing OCS OSRP.

You may modify an existing response plan covering a lease or
facility on the OCS to include a lease or facility in State waters
located seaward of the coast line. Since this OSRP would cover more than
one lease or facility, it would be considered a Regional Response Plan.
You should refer to Sec. 254.3 and contact the appropriate regional
BSEE office if you have any questions on how to prepare this Regional
Response Plan.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36153, June 6, 2016]

Sec. 254.52 Following the format for an OCS OSRP.

You may develop a response OSRP following the requirements for plans
for OCS facilities found in subpart B of this part.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36153, June 6, 2016]

Sec. 254.53 Submitting an OSRP developed under State requirements.

(a) You may submit a response plan to BSEE for approval that you
developed in accordance with the laws or regulations of the appropriate
State.

[[Page 309]]

The OSRP must contain all the elements the State and OPA require and
must:
(1) Be consistent with the requirements of the National Contingency
Plan and appropriate Area Contingency Plan(s).
(2) Identify a qualified individual and require immediate
communication between that person and appropriate Federal officials and
response personnel if there is a spill.
(3) Identify any private personnel and equipment necessary to
remove, to the maximum extent practicable, a worst case discharge as
defined in Sec. 254.47. The plan must provide proof of contractual
services or other evidence of a contractual agreement with any OSRO's or
spill management team members who are not employees of the owner or
operator.
(4) Describe the training, equipment testing, periodic unannounced
drills, and response actions of personnel at the facility. These must
ensure both the safety of the facility and the mitigation or prevention
of a discharge or the substantial threat of a discharge.
(5) Describe the procedures you will use to periodically update and
resubmit the plan for approval of each significant change.
(b) Your plan developed under State requirements also must include
the following information:
(1) A list of the facilities and leases the plan covers and a map
showing their location;
(2) A list of the types of oil handled, stored, or transported at
the facility;
(3) Name and address of the State agency to whom the plan was
submitted;
(4) Date you submitted the plan to the State;
(5) If the plan received formal approval, the name of the approving
organization, the date of approval, and a copy of the State agency's
approval letter if one was issued; and
(6) Identification of any regulations or standards used in preparing
the plan.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36153, June 6, 2016]

Sec. 254.54 Spill prevention for facilities located in State waters
seaward of the coast line.

In addition to your OSRP, you must submit to the Regional Supervisor
a description of the steps you are taking to prevent spills of oil or
mitigate a substantial threat of such a discharge. You must identify all
State or Federal safety or pollution prevention requirements that apply
to the prevention of oil spills from your facility, and demonstrate your
compliance with these requirements. You also should include a
description of industry safety and pollution prevention standards your
facility meets. The Chief, OSPD may prescribe additional equipment or
procedures for spill prevention if it is determined that your efforts to
prevent spills do not reflect good industry practices.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36153, June 6, 2016]

Sec. 254.55 Spill response plans for facilities located
in Alaska State waters seaward of the coast line
in the Chukchi and Beaufort Seas.

Response plans for facilities conducting exploratory drilling
operations from a MODU seaward of the coast line in Alaska State waters
in the Chukchi and Beaufort Seas must follow the requirements contained
within subpart E of this part, in addition to the other requirements of
this subpart. Such response plans must address how the source control
procedures selected to comply with State law will be integrated into the
planning, training, and exercise requirements of Sec. Sec. 254.70(a),
254.90(a), and 254.90(c), in the event that the proposed operations do
not incorporate the capping stack, cap and flow system, containment
dome, and/or other similar subsea and surface devices and equipment and
vessels referenced in those sections.

[81 FR 46563, July 15, 2016]

Subpart E_Oil-Spill Response Requirements for Facilities Located on the
Arctic OCS

Source: 81 FR 46564, July 15, 2016, unless otherwise noted.

[[Page 310]]

Sec. 254.65 Purpose.

This subpart describes the additional requirements for preparing
OSRPs and maintaining oil spill preparedness for facilities conducting
exploratory drilling operations from a mobile offshore drilling unit
(MODU) on the Arctic OCS.

Sec. Sec. 254.66-254.69 [Reserved]

Sec. 254.70 What are the additional requirements for facilities
conducting exploratory drilling from a MODU on the Arctic OCS?

In addition to meeting the applicable requirements of this part,
your OSRP must:
(a) Describe how the relevant personnel, equipment, materials, and
support vessels associated with the capping stack, cap and flow system,
containment dome, and other similar subsea and surface devices and
equipment and vessels will be integrated into oil spill response
incident action planning;
(b) Describe how you will address human factors, such as cold stress
and cold related conditions, associated with oil spill response
activities in adverse weather conditions and their impacts on decision-
making and health and safety; and
(c) Undergo plan-holder review prior to handling, storing, or
transporting oil in connection with seasonal exploratory drilling
activities, and all resulting modifications must be submitted to the
Regional Supervisor. If this review does not result in modifications,
you must inform the Regional Supervisor in writing that there are no
changes. The requirements of this paragraph (c) are in lieu of the
requirements in Sec. 254.30(a).

Sec. Sec. 254.71-254.79 [Reserved]

Sec. 254.80 What additional information must I include in the
``Emergency response action plan'' section for facilities conducting
exploratory drilling from a MODU on the Arctic OCS?

In addition to the requirements in Sec. 254.23, you must include
the following information in the emergency response action plan section
of your OSRP:
(a) A description of your ice intervention practices and how they
will improve the effectiveness of the oil spill response options and
strategies that are listed in your OSRP in the presence of sea ice. When
developing the ice intervention practices for your OSRP, you must
consider, at a minimum, the use of specialized tactics, modified
response equipment, ice management assist vessels, and technologies for
the identification, tracking, containment and removal of oil in ice.
(b) On areas of the Arctic OCS where a planned shore-based response
would not satisfy Sec. 254.1(a):
(1) A list of all resources required to ensure an effective
offshore-based response capable of operating in adverse weather
conditions. This list must include a description of how you will ensure
the shortest possible transit times, including but not limited to
establishing an offshore resource management capability (e.g., sea-based
staging, maintenance, and berthing logistics); and
(2) A list and description of logistics resupply chains, including
waste management, that effectively factor in the remote and limited
infrastructure that exists in the Arctic and ensure you can adequately
sustain all oil spill response activities for the duration of the
response. The components of the logistics supply chain include, but are
not limited to:
(i) Personnel and equipment transport services;
(ii) Airfields and types of aircraft that can be supported;
(iii) Capabilities to mobilize supplies (e.g., response equipment,
fuel, food, fresh water) and personnel to the response sites;
(iv) Onshore staging areas, storage areas that may be used en-route
to staging areas, and camp facilities to support response personnel
conducting offshore, nearshore and shoreline response; and
(v) Management of recovered fluid and contaminated debris and
response materials (e.g., oiled sorbents), as well as waste streams
generated at offshore and on-shore support facilities (e.g., sewage,
food, and medical).
(c) A description of the system you will use to maintain real-time
location

[[Page 311]]

tracking for all response resources while operating, transiting, or
staging/maintaining such resources during a spill response.

Sec. Sec. 254.81-254.89 [Reserved]

Sec. 254.90 What are the additional requirements for exercises
of your response personnel and equipment for facilities conducting
exploratory drilling from a MODU on the Arctic OCS?

In addition to the requirements in Sec. 254.42, the following
requirements apply to exercises for your response personnel and
equipment for facilities conducting exploratory drilling from a MODU on
the Arctic OCS:
(a) You must incorporate the personnel, materials, and equipment
identified in Sec. 254.70(a), the safe working practices identified in
Sec. 254.70(b), the ice intervention practices described in Sec.
254.80(a), the offshore-based response requirements in Sec. 254.80(b),
and the resource tracking requirements in Sec. 254.80(c) into your
spill-response training and exercise activities.
(b) For each season in which you plan to conduct exploratory
drilling operations from a MODU on the Arctic OCS, you must notify the
Regional Supervisor 60 days prior to handling, storing, or transporting
oil.
(c) After the Regional Supervisor receives notice pursuant to Sec.
254.90(b), the Regional Supervisor may direct you to deploy and operate
your spill response equipment and/or your capping stack, cap and flow
system, and containment dome, and other similar subsea and surface
devices and equipment and vessels, as part of announced or unannounced
exercises or compliance inspections. For the purposes of this section,
spill response equipment does not include the use of blowout preventers,
diverters, heavy weight mud to kill the well, relief wells, or other
similar conventional well control options.

PART 256_LEASING OF SULPHUR OR OIL AND GAS IN THE OUTER CONTINENTAL SHELF--
Table of Contents

Subpart A_Outer Continental Shelf Oil, Gas, and Sulphur Management,
General

Sec.
256.1 Purpose.
256.7 Cross references.
256.8-256.12 [Reserved]

Subpart B_Assignments, Transfers, and Extensions

256.70 Extension of lease by drilling or well reworking operations.
256.71 Directional drilling.
256.72 Compensatory payments as production.
256.73 Effect of suspensions on lease term.

Subpart C_Termination of Leases

256.77 Cancellation of leases.

Subpart D_Section 6 Leases

256.79 Effect of regulations on lease.

Authority: 31 U.S.C. 9701, 42 U.S.C. 6213, 43 U.S.C. 1334, Pub. L.
109-432.

Source: 76 FR 64462, Oct. 18, 2011, unless otherwise noted.

Subpart A_Outer Continental Shelf Oil, Gas, and Sulphur Management,
General

Sec. 256.1 Purpose.

The purpose of the regulations in 30 CFR part 256 is to establish
the procedures under which the Secretary of the Interior (Secretary)
will exercise the authority to administer a leasing program for oil, gas
and sulphur. The procedures under which the Secretary will exercise the
authority to administer a program to grant rights-of-way, are addressed
in part 250, subpart J.

Sec. 256.7 Cross references.

(a) For Bureau of Safety and Environmental Enforcement (BSEE)
regulations governing exploration, development and production on leases,
see 30 CFR parts 250 and 270.
(b) For BSEE regulations governing the appeal of an order or
decision issued under the regulations in this part, see 30 CFR part 290.

[[Page 312]]

(c) For multiple use conflicts, see the Environmental Protection
Agency listing of ocean dumping sites--40 CFR part 228.
(d) For related National Oceanic and Atmospheric Administration
programs see:
(1) Marine sanctuary regulations, 15 CFR part 922;
(2) Fishermen's Contingency Fund, 50 CFR part 296;
(3) Coastal Energy Impact Program, 15 CFR part 931;
(e) For Coast Guard regulations on the oil spill liability of
vessels and operators, see 33 CFR parts 132, 135, and 136.
(f) For Coast Guard regulations on port access routes, see 33 CFR
part 164.
(g) For compliance with the National Environmental Policy Act, see
40 CFR parts 1500 through 1508.
(h) For Department of Transportation regulations on offshore
pipeline facilities, see 49 CFR part 195.
(i) For Department of Defense regulations on military activities on
offshore areas, see 32 CFR part 252.
(j) For Bureau of Ocean Energy Management (BOEM) regulations, see 30
CFR chapter V.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36153, June 6, 2016]

Subpart B_Assignments, Transfers, and Extensions

Source: 76 FR 64462, Oct. 18, 2011, Redesignated at 81 FR 36153,
June 6, 2016.

Sec. 256.70 Extension of lease by drilling or well reworking operations.

The term of a lease shall be extended beyond the primary term so
long as drilling or well reworking operations are approved by the
Secretary according to the conditions set forth in 30 CFR 250.180.

Sec. 256.71 Directional drilling.

In accordance with a BOEM-approved exploration plan or development
and production plan, a lease may be maintained in force by directional
wells drilled under the leased area from surface locations on adjacent
or adjoining land not covered by the lease. In such circumstances,
drilling shall be considered to have commenced on the leased area when
drilling is commenced on the adjacent or adjoining land for the purpose
of directional drilling under the leased area through any directional
well surfaced on adjacent or adjoining land. Production, drilling or
reworking of any such directional well shall be considered production or
drilling or reworking operations on the leased area for all purposes of
the lease.

Sec. 256.72 Compensatory payments as production.

If an oil and gas lessee makes compensatory payments and if the
lease is not being maintained in force by other production of oil or gas
in paying quantities or by other approved drilling or reworking
operations, such payments shall be considered as the equivalent of
production in paying quantities for all purposes of the lease.

Sec. 256.73 Effect of suspensions on lease term.

(a) A suspension may extend the term of a lease (see 30 CFR 250.171)
with the extension being the length of time the suspension is in effect
except as provided in paragraph (b) of this section.
(b) A Directed Suspension does not extend the lease term when the
Regional Supervisor directs a suspension because of:
(1) Gross negligence; or
(2) A willful violation of a provision of the lease or governing
regulations.
(c) BSEE may issue suspensions for a period of up to 5 years per
suspension. The Regional Supervisor will set the length of the
suspension based on the conditions of the individual case involved. BSEE
may grant consecutive suspensions. For more information on suspension of
operations or production refer to the section under the heading
``Suspensions'' in 30 CFR part 250, subpart A.

Subpart C_Termination of Leases

Source: 76 FR 64462, Oct. 18, 2011, Redesignated at 81 FR 36153,
June 6, 2016.

Sec. 256.77 Cancellation of leases.

(a) Any nonproducing lease issued under the act may be cancelled by
the

[[Page 313]]

authorized officer whenever the lessee fails to comply with any
provision of the act or lease or applicable regulations, if such failure
to comply continues for 30 days after mailing of notice by registered or
certified letter to the lease owner at the owner's record post office
address. Any such cancellation is subject to judicial review as provided
in section 23(b) of the Act.
(b) Producing leases issued under the Act may be cancelled by the
Secretary whenever the lessee fails to comply with any provision of the
Act, applicable regulations or the lease only after judicial proceedings
as prescribed by section 5(d) of the Act.
(c) Any lease issued under the Act, whether producing or not, shall
be canceled by the authorized officer upon proof that it was obtained by
fraud or misrepresentation, and after notice and opportunity to be heard
has been afforded to the lessee.
(d) Pursuant to section 5(a) of the Act, the Secretary may cancel a
lease when:
(1) Continued activity pursuant to such lease would probably cause
serious harm or damage to life, property, any mineral, National security
or defense, or to the marine, coastal or human environment;
(2) The threat of harm or damage will not disappear or decrease to
an acceptable extent within a reasonable period of time; and
(3) The advantages of cancellation outweigh the advantages of
continuing such lease or permit in force. Procedures and conditions
contained in Sec. 550.182 shall apply as appropriate.

Subpart D_Section 6 Leases

Source: 76 FR 64462, Oct. 18, 2011, Redesignated at 81 FR 36153,
June 6, 2016.

Sec. 256.79 Effect of regulations on lease.

(a) All regulations in this part, insofar as they are applicable,
shall supersede the provisions of any lease which is maintained under
section 6(a) of the Act. However, the provisions of a lease relating to
area, minerals, rentals, royalties (subject to sections 6(a) (8) and (9)
of the Act), and term (subject to section 6(a)(10) of the Act and, as to
sulfur, subject to section 6(b)(2) of the Act) shall continue in effect,
and, in the event of any conflict or inconsistency, shall take
precedence over these regulations.
(b) A lease maintained under section 6(a) of the Act shall also be
subject to all operating and conservation regulations applicable to the
OCS. In addition, the regulations relating to geophysical and geological
exploratory operations and to pipeline rights-of-way are applicable, to
the extent that those regulations are not contrary to or inconsistent
with the lease provisions relating to area, the minerals, rentals,
royalties and term. The lessee shall comply with any provision of the
lease as validated, the subject matter of which is not covered in the
regulations in this part.

PARTS 259 260 [RESERVED]

PART 270_NONDISCRIMINATION IN THE OUTER CONTINENTAL SHELF--Table of Contents

Sec.
270.1 Purpose.
270.2 Application of this part.
270.3 Definitions.
270.4 Discrimination prohibited.
270.5 Complaint.
270.6 Process.
270.7 Remedies.

Authority: 43 U.S.C. 1863.

Source: 76 FR 64462, Oct. 18, 2011, unless otherwise noted.

Sec. 270.1 Purpose.

The purpose of this part is to implement the provisions of section
604 of the OCSLA of 1978 which provides that ``no person shall, on the
grounds of race, creed, color, national origin, or sex, be excluded from
receiving or participating in any activity, sale, or employment,
conducted pursuant to the provisions of * * * the Outer Continental
Shelf Lands Act.''

Sec. 270.2 Application of this part.

This part applies to any contract or subcontract entered into by a
lessee or by a contractor or subcontractor of a lessee after the
effective date of these regulations to provide goods, services,
facilities, or property in an amount of $10,000 or more in connection
with any activity related to the exploration for

[[Page 314]]

or development and production of oil, gas, or other minerals or
materials in the OCS under the Act.

Sec. 270.3 Definitions.

As used in this part, the following terms shall have the following
meanings:
Contract means any business agreement or arrangement (in which the
parties do not stand in the relationship of employer and employee)
between a lessee and any person which creates an obligation to provide
goods, services, facilities, or property.
Lessee means the party authorized by a lease, grant of right-of-way,
or an approved assignment thereof to explore, develop, produce, or
transport oil, gas, or other minerals or materials in the OCS pursuant
to the Act and this part.
Person means a person or company, including but not limited to, a
corporation, partnership, association, joint stock venture, trust,
mutual fund, or any receiver, trustee in bankruptcy, or other official
acting in a similar capacity for such company.
Subcontract means any business agreement or arrangement (in which
the parties do not stand in the relationship of employer and employee)
between a lessee's contractor and any person other than a lessee that is
in any way related to the performance of any one or more contracts.

Sec. 270.4 Discrimination prohibited.

No contract or subcontract to which this part applies shall be
denied to or withheld from any person on the grounds of race, creed,
color, national origin, or sex.

Sec. 270.5 Complaint.

(a) Whenever any person believes that he or she has been denied a
contract or subcontract to which this part applies on the grounds of
race, creed, color, national origin, or sex, such person may complain of
such denial or withholding to the Regional Director of the OCS Region in
which such action is alleged to have occurred. Any complaint filed under
this part must be submitted in writing to the appropriate Regional
Director not later than 180 days after the date of the alleged unlawful
denial of a contract or subcontract which is the basis of the complaint.
(b) The complaint referred to in paragraph (a) of this section shall
be accompanied by such evidence as may be available to a person and
which is relevant to the complaint including affidavits and other
documents.
(c) Whenever any person files a complaint under this part, the
Regional Director with whom such complaint is filed shall give written
notice of such filing to all persons cited in the complaint no later
than 10 days after receipt of such complaint. Such notice shall include
a statement describing the alleged incident of discrimination, including
the date and the names of persons involved in it.

Sec. 270.6 Process.

Whenever a Regional Director determines on the basis of any
information, including that which may be obtained under Sec. 270.5 of
this part, that a violation of or failure to comply with any provision
of this subpart probably occurred, the Regional director shall undertake
to afford the complainant and the person(s) alleged to have violated the
provisions of this part an opportunity to engage in informal
consultations, meetings, or any other form of communications for the
purpose of resolving the complaint. In the event such communications or
consultations result in a mutually satisfactory resolution of the
complaint, the complainant and all persons cited in the complaint shall
notify the Regional Director in writing of their agreement to such
resolution. If either the complainant or the person(s) alleged to have
wrongfully discriminated fail to provide such written notice within a
reasonable period of time, the Regional Director must proceed in
accordance with the provisions of 30 CFR 250, subpart N.

Sec. 270.7 Remedies.

In addition to the penalties available under 30 CFR part 250,
subpart N, the Director may invoke any other remedies available to him
or her under the Act or regulations for the lessee's failure to comply
with provisions of the Act, regulations, or lease.

[[Page 315]]

PART 280_PROSPECTING FOR MINERALS OTHER THAN OIL, GAS, AND SULPHUR
ON THE OUTER CONTINENTAL SHELF--Table of Contents

Subparts A-B [Reserved]

Subpart C_Obligations Under This Part

Interrupted Activities

Sec.
280.20-280.24 [Reserved]
280.25 When may BSEE require me to stop activities under this part?
280.26 When may I resume activities?
280.27 When may BSEE cancel my permit?
280.28 May I relinquish my permit?

Subparts D-E [Reserved]

Authority: 43 U.S.C. 1334.

Source: 76 FR 64462, Oct. 18, 2011, unless otherwise noted.

Subparts A-B [Reserved]

Subpart C_Obligations Under This Part

Interrupted Activities

Sec. Sec. 280.20-280.24 [Reserved]

Sec. 280.25 When may BSEE require me to stop activities under this part?

(a) We may temporarily stop prospecting or scientific research
activities under a permit when the Regional Director determines that:
(1) Activities pose a threat of serious, irreparable, or immediate
harm. This includes damage to life (including fish and other aquatic
life), property, and any minerals (in areas leased or not leased), to
the marine, coastal, or human environment, or to an archaeological
resource;
(2) You failed to comply with any applicable law, regulation, order
or provision of the permit. This would include the required submission
of reports, well records or logs, and G&G data and information within
the time specified; or
(3) Stopping the activities is in the interest of National security
or defense.
(b) The Regional Director will advise you either orally or in
writing of the procedures to temporarily stop activities. We will
confirm an oral notification in writing and deliver all written
notifications by courier or certified/registered mail. You must stop all
activities under a permit as soon as you receive an oral or written
notification.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36153, June 6, 2016]

Sec. 280.26 When may I resume activities?

The Regional Director will advise you when you may start your permit
activities again.

Sec. 280.27 When may BSEE cancel my permit?

The Regional Director may cancel a permit at any time.
(a) If we cancel your permit, the Regional Director will advise you
by certified or registered mail 30 days before the cancellation date and
will state the reason.
(b) After we cancel your permit, you are still responsible for
proper abandonment of any drill site according to the requirements of 30
CFR 251.7(b)(8). You must comply with all other obligations specified in
this part or in the permit.

Sec. 280.28 May I relinquish my permit?

(a) You may relinquish your permit at any time by advising the
Bureau of Ocean Energy Management Regional Director by certified or
registered mail 30 days in advance.
(b) After you relinquish your permit, you are still responsible for
proper abandonment of any drill sites according to the requirements of
30 CFR 251.7(b)(8). You must also comply with all other obligations
specified in this part or in the permit.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36153, June 6, 2016]

Subparts D-E [Reserved]

PART 281 [RESERVED]

[[Page 316]]

PART 282_OPERATIONS IN THE OUTER CONTINENTAL SHELF FOR MINERALS OTHER THAN
OIL, GAS, AND SULPHUR--Table of Contents

Subpart A_General

Sec.
282.0 Authority for information collection.
282.1 Purpose and authority.
282.2 Scope.
282.3 Definitions.
282.4 [Reserved]
282.5 Disclosure of data and information to the public.
282.6 Disclosure of data and information to an adjacent State.
282.7 Jurisdictional controversies.

Subpart B_Jurisdiction and Responsibilities of Director

282.10 Jurisdiction and responsibilities of Director.
282.11 Director's authority.
282.12 Director's responsibilities.
282.13 Suspension of production or other operations.
282.14 Noncompliance, remedies, and penalties.
282.15 [Reserved]

Subpart C_Obligations and Responsibilities of Lessees

282.20 [Reserved]
282.21 Plans, general.
282.22-282.26 [Reserved]
282.27 Conduct of operations.
282.28 Environmental protection measures.
282.29-282.30 [Reserved]
282.31 Suspension of production or other operations.

Subpart D_Payments

282.40 [Reserved]
282.41 Method of royalty calculation
282.42 [Reserved]

Subpart E_Appeals

282.50 Appeals.

Authority: 43 U.S.C. 1334.

Source: 76 FR 64462, Oct. 18, 2011, unless otherwise noted.

Subpart A_General

Sec. 282.0 Authority for information collection.

(a) The information collection requirements in this part have been
approved by the Office of Management and Budget under 44 U.S.C. 3507 and
assigned clearance number 1014-0021. The information is being collected
to inform the Bureau of Safety and Environmental Enforcement (BSEE) of
general mining operations in the Outer Continental Shelf (OCS). The
information will be used to ensure that operations are conducted in a
safe and environmentally responsible manner in compliance with governing
laws and regulations. The requirement to respond is mandatory.
(b) Send comments regarding any aspect of the collection of
information under this part, including suggestions for reducing the
burden, to: Information Collection Clearance Officer, Bureau of Safety
and Environmental Enforcement, 45600 Woodland Road, Sterling, VA 20166.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36153, June 6, 2016]

Sec. 282.1 Purpose and authority.

(a) The Act authorizes the Secretary to prescribe such rules and
regulations as may be necessary to carry out the provisions of the Act
(43 U.S.C. 1334). The Secretary is authorized to prescribe and amend
regulations that the Secretary determines to be necessary and proper in
order to provide for the prevention of waste, conservation of the
natural resources of the OCS, and the protection of correlative rights
therein. In the enforcement of safety, environmental, and conservation
laws and regulations, the Secretary is authorized to cooperate with
adjacent States and other Departments and Agencies of the Federal
Government.
(b) Subject to the supervisory authority of the Secretary, and
unless otherwise specified, the regulations in this part shall be
administered by the Director of BSEE.

Sec. 282.2 Scope.

The rules and regulations in this part apply as of their effective
date to all operations conducted under a mineral lease for OCS minerals
other than oil, gas, or sulphur issued under the provisions of section
8(k) of the Act.

[[Page 317]]

Sec. 282.3 Definitions.

When used in this part, the following terms shall have the following
meaning:
Act means the OCS Lands Act, as amended (43 U.S.C. 1331 et seq.).
Adjacent State means with respect to any activity proposed,
conducted, or approved under this part, any coastal State:
(1) That is, or is proposed to be, receiving for processing,
refining, or transshipment OCS mineral resources commercially recovered
from the seabed;
(2) That is used, or is scheduled to be used, as a support base for
prospecting, exploration, testing, or mining activities; or
(3) In which there is a reasonable probability of significant effect
on land or water uses from such activity.
Contingency Plan means a plan for action to be taken in emergency
situations.
Data means geological and geophysical (G&G) facts and statistics or
samples which have not been analyzed, processed, or interpreted.
Development means those activities which take place following the
discovery of minerals in paying quantities including geophysical
activities, drilling, construction of offshore facilities, and operation
of all onshore support facilities, which are for the purpose of
ultimately producing the minerals discovered.
Director means the Director of BSEE of the U.S. Department of the
Interior or an official authorized to act on the Director's behalf.
Exploration means the process of searching for minerals on a lease
including:
(1) Geophysical surveys where magnetic, gravity, seismic, or other
systems are used to detect or imply the presence of minerals;
(2) Any drilling including the drilling of a borehole in which the
discovery of a mineral other than oil, gas, or sulphur is made and the
drilling of any additional boreholes needed to delineate any mineral
deposits; and
(3) The taking of sample portions of a mineral deposit to enable the
lessee to determine whether to proceed with development and production.
Geological sample means a collected portion of the seabed, the
subseabed, or the overlying waters (when obtained for geochemical
analysis) acquired while conducting postlease mining activities.
Governor means the Governor of a State or the person or entity
designated by, or pursuant to, State law to exercise the power granted
to a Governor.
Information means G&G data that have been analyzed, processed, or
interpreted.
Lease means one of the following, whichever is required by the
context: Any form of authorization which is issued under section 8 or
maintained under section 6 of the Acts and which authorizes exploration
for, and development and production of, specific minerals; or the area
covered by that authorization.
Lessee means the person authorized by a lease, or an approved
assignment thereof, to explore for and develop and produce the leased
deposits in accordance with the regulations in this chapter. The term
includes all parties holding that authority by or through the lessee.
Major Federal action means any action or proposal by the Secretary
which is subject to the provisions of section 102(2)(C) of the National
Environmental Policy Act (NEPA) (i.e., an action which will have a
significant impact on the quality of the human environment requiring
preparation of an Environmental Impact Statement (EIS) pursuant to
section 102(2)(C) of NEPA).
Marine environment means the physical, atmospheric, and biological
components, conditions, and factors which interactively determine the
productivity, state, condition, and quality of the marine ecosystem,
including the waters of the high seas, the contiguous zone, transitional
and intertidal areas, salt marshes, and wetlands within the coastal zone
and on the OCS.
Minerals include oil, gas, sulphur, geopressured-geothermal and
associated resources, and all other minerals which are authorized by an
Act of Congress to be produced from ``public lands'' as defined in
section 103 of the

[[Page 318]]

Federal Land Policy and Management Act of 1976.
OCS mineral means any mineral deposit or accretion found on or below
the surface of the seabed but does not include oil, gas, or sulphur;
salt or sand and gravel intended for use in association with the
development of oil, gas, or sulphur; or source materials essential to
production of fissionable materials which are reserved to the United
States pursuant to section 12(e) of the Act.
Operator means the individual, partnership, firm, or corporation
having control or management of operations on the lease or a portion
thereof. The operator may be a lessee, designated agent of the lessee,
or holder of rights under an approved operating agreement.
Outer Continental Shelf means all submerged lands lying seaward and
outside of the area of lands beneath navigable waters as defined in
section 2 of Submerged Lands Act (43 U.S.C. 1301) and of which the
subsoil and seabed appertain to the United States and are subject to its
jurisdiction and control.
Person means a citizen or national of the United States; an alien
lawfully admitted for permanent residency in the United States as
defined in 8 U.S.C. 1101(a)(20); a private, public, or municipal
corporation organized under the laws of the United States or of any
State or territory thereof; an association of such citizens, nationals,
resident aliens or private, public, or municipal corporations, States,
or political subdivisions of States; or anyone operating in a manner
provided for by treaty or other applicable international agreements. The
term does not include Federal Agencies.
Secretary means the Secretary of the Interior or an official
authorized to act on the Secretary's behalf.
Testing means removing bulk samples for processing tests and
feasibility studies and/or the testing of mining equipment to obtain
information needed to develop a detailed Mining Plan.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36153, June 6, 2016]

Sec. 282.4 [Reserved]

Sec. 282.5 Disclosure of data and information to the public.

(a) The Director shall make data, information, and samples available
in accordance with the requirements and subject to the limitations of
the Act, the Freedom of Information Act (5 U.S.C. 552), and the
implementing regulations (43 CFR part 2).
(b) Geophysical data, processed G&G information, interpreted G&G
information, and other data and information submitted pursuant to the
requirements of this part shall not be available for public inspection
without the consent of the lessee so long as the lease remains in
effect, unless the Director determines that earlier limited release of
such information is necessary for the unitization of operations on two
or more leases, to ensure proper Mining Plans for a common ore body, or
to promote operational safety. When the Director determines that early
limited release of data and information is necessary, the data and
information shall be shown only to persons with a direct interest in the
affected lease(s), unitization agreement, or joint Mining Plan.
(c) Geophysical data, processed geophysical information and
interpreted geophysical information collected on a lease with high
resolution systems (including, but not limited to, bathymetry, side-scan
sonar, subbottom profiler, and magnetometer) in compliance with
stipulations or orders concerning protection of environmental aspects of
the lease may be made available to the public 60 days after submittal to
the Director, unless the lessee can demonstrate to the satisfaction of
the Director that release of the information or data would unduly damage
the lessee's competitive position.

Sec. 282.6 Disclosure of data and information to an adjacent State.

(a) Proprietary data, information, and samples submitted to BSEE
pursuant to the requirements of this part shall be made available for
inspection by representatives of adjacent State(s) upon request by the
Governor(s) in accordance with paragraphs (b) and (c) of this section.

[[Page 319]]

(b) Disclosure shall occur only after the Governor has entered into
an agreement with the Secretary providing that:
(1) The confidentiality of the information shall be maintained;
(2) In any action commenced against the Federal Government or the
State for failure to protect the confidentiality of proprietary
information, the Federal Government or the State, as the case may be,
may not raise as a defense any claim of sovereign immunity or any claim
that the employee who revealed the proprietary information, which is the
basis of the suit, was acting outside the scope of the person's
employment in revealing the information;
(3) The State agrees to hold the United States harmless for any
violation by the State or its employees or contractors of the agreement
to protect the confidentiality of proprietary data, information, and
samples; and
(c) The data, information, and samples available for inspection by
representatives of adjacent State(s) pursuant to an agreement shall be
related to leased lands.

Sec. 282.7 Jurisdictional controversies.

In the event of a controversy between the United States and a State
as to whether certain lands are subject to Federal or State
jurisdiction, either the Governor of the State or the Secretary may
initiate negotiations in an attempt to settle the jurisdictional
controversy. With the concurrence of the Attorney General, the Secretary
may enter into an agreement with a State with respect to OCS mineral
activities and to payment and impounding of rents, royalties, and other
sums and with respect to the issuance or nonissuance of new leases
pending settlement of the controversy.

Subpart B_Jurisdiction and Responsibilities of Director

Sec. 282.10 Jurisdiction and responsibilities of Director.

Subject to the authority of the Secretary, the following activities
are subject to the regulations in this part and are under the
jurisdiction of the Director: Exploration, testing, and mining
operations together with the associated environmental protection
measures needed to permit those activities to be conducted in an
environmentally responsible manner; handling, measurement, and
transportation of OCS minerals; and other operations and activities
conducted pursuant to a lease issued under 30 CFR part 581, or pursuant
to a right of use and easement granted under 30 CFR 582.30, by or on
behalf of a lessee or the holder of a right of use and easement.

Sec. 282.11 Director's authority.

(a)-(c) [Reserved]
(d)(1) The Director may approve the consolidation of two or more OCS
mineral leases or portions of two or more OCS mineral leases into a
single mining unit requested by lessees, or the Director may require
such consolidation when the operation of those leases or portions of
leases as a single mining unit is in the interest of conservation of the
natural resources of the OCS or the prevention of waste. A mining unit
may also include all or portions of one or more OCS mineral leases with
all or portions of one or more adjacent State leases for minerals in a
common orebody. A single unit operator shall be responsible for
submission of required Delineation, Testing, and Mining Plans covering
OCS mineral operations for an approved mining unit.
(2) Operations such as exploration, testing, and mining activities
conducted in accordance with an approved plan on any lease or portion of
a lease which is subject to an approved mining unit shall be considered
operations on each of the leases that is made subject to the approved
mining unit.
(3) Minimum royalty paid pursuant to a Federal lease, which is
subject to an approved mining unit, is creditable against the production
royalties allocated to that Federal lease during the lease year for
which the minimum royalty is paid.
(4) Any OCS minerals produced from State and Federal leases which
are subject to an approved mining unit shall be accounted for separately
unless a method of allocating production between State and Federal
leases has been approved by the Director and the appropriate State
official.

[[Page 320]]

Sec. 282.12 Director's responsibilities.

(a) The Director is responsible for the regulation of activities to
assure that all operations conducted under a lease or right of use and
easement are conducted in a manner that protects the environment and
promotes orderly development of OCS mineral resources. Those activities
are to be designed to prevent serious harm or damage to, or waste of,
any natural resource (including OCS mineral deposits and oil, gas, and
sulphur resources in areas leased or not leased), any life (including
fish and other aquatic life), property, or the marine, coastal, or human
environment.
(b)-(d) [Reserved]
(e) The Director shall assure that a scheduled onsite compliance
inspection of each facility which is subject to regulations in this part
is conducted at least once a year. The inspection shall be to determine
that the lessee is in compliance with the requirements of the law;
provisions of the lease; the approved Delineation, Testing, or Mining
Plan; and the regulations in this part. Additional unscheduled onsite
inspections shall be conducted without advance notice to the lessee to
assure compliance with the provisions of applicable law; the lease; the
approved Delineation, Testing, or Mining Plan; and the regulations in
this part.
(f)(1) The Director shall, after completion of the technical and
environmental evaluations, approve, disapprove, or require modification
of the lessee's requests, applications, plans, and notices submitted
pursuant to the provisions of this part; issue orders to govern lease
operations; and require compliance with applicable provisions of the
law, the regulations, the lease, and the approved Delineation, Testing,
or Mining Plans. The Director may give oral orders or approvals whenever
prior approval is required before the commencement of an operation or
activity. Oral orders or approvals given in response to a written
request shall be confirmed in writing within 3 working days after
issuance of the order or granting of the oral approval.
(2) The Director shall, after completion of the technical and
environmental evaluations, approve, disapprove, or require modification,
as appropriate, of the design plan, fabrication plan, and installation
plan for platforms, artificial islands, and other installations and
devices permanently or temporarily attached to the seabed. The approval,
disapproval, or requirement to modify such plans may take the form of a
condition of granting a right of use and easement under paragraph (a) of
this section or as authorized under any lease issued or maintained under
the Act.
(g) [Reserved]
(h) The Director may prescribe or approve, in writing or orally,
departures from the operating requirements of the regulations of this
part when such departures are necessary to facilitate the proper
development of a lease; to conserve natural resources; or to protect
life (including fish and other aquatic life), property, or the marine,
coastal, or human environment.

Sec. 282.13 Suspension of production or other operations.

(a) The Director may direct the suspension or temporary prohibition
of production or any other operation or activity on all or any part of a
lease when it has been determined that such suspension or temporary
prohibition is in the National interest to:
(1) Facilitate proper development of a lease including a reasonable
time to develop a mine and construct necessary support facilities, or
(2) Allow for the construction or negotiation for use of
transportation facilities.
(b) The Director may also direct or, at the request of the lessee,
approve a suspension or temporary prohibition of production or any other
operation or activity, if:
(1) The lessee failed to comply with a provision of applicable law,
regulation, order, or the lease;
(2) There is a threat of serious, irreparable, or immediate harm or
damage to life (including fish and other aquatic life), property, any
mineral deposit, or the marine, coastal, or human environment;
(3) The suspension or temporary prohibition is in the interest of
National security or defense;
(4) The suspension or temporary prohibition is necessary for the
initiation

[[Page 321]]

and conduct of an environmental evaluation to define mitigation measures
to avoid or minimize adverse environmental impacts.
(5) The suspension or temporary prohibition is necessary to
facilitate the installation of equipment necessary for safety of
operations and protection of the environment;
(6) The suspension or temporary prohibition is necessary to allow
for undue delays encountered by the lessee in obtaining required permits
or consents, including administrative or judicial challenges or appeals;
(7) The Director determines that continued operations would result
in premature abandonment of a producing mine, resulting in the loss of
otherwise recoverable OCS minerals;
(8) The Director determines that the lessee cannot successfully
operate a producing mine due to market conditions that are either
temporary in nature or require temporary shutdown and reinvestment in
order for the lessee to adapt to the conditions; or
(9) The suspension or temporary prohibition is necessary to comply
with judicial decrees prohibiting production or any other operation or
activity, or the permitting of those activities, effective the date set
by the court for that prohibition.
(c) When the Director orders or approves a suspension or a temporary
prohibition of operation or activity including production on all of a
lease pursuant to paragraph (a) or (b) of this section, the term of the
lease shall be extended for a period of time equal to the period of time
that the suspension or temporary prohibition is in effect, except that
no lease shall be so extended when the suspension or temporary
prohibition is the result of the lessee's gross negligence or willful
violation of a provision of the lease or governing regulations.
(d) The Director may, at any time within the period prescribed for a
suspension or temporary prohibition issued pursuant to paragraph (b)(2)
of this section, require the lessee to submit a Delineation, Testing, or
Mining Plan to the Bureau of Ocean Energy Management for approval in
accordance with the requirements for the approval of such plans in part
582 of this title.
(e)(1) When the Director orders or issues a suspension or a
temporary prohibition pursuant to paragraph (b)(2) of this section, the
Director may require the lessee to conduct site-specific studies to
identify and evaluate the cause(s) of the hazard(s) generating the
suspension or temporary prohibition, the potential for damage from the
hazard(s), and the measures available for mitigating the hazard(s). The
nature, scope, and content of any study shall be subject to approval by
the Director. The lessee shall furnish copies and all results of any
such study to the Director. The cost of the study shall be borne by the
lessee unless the Director arranges for the cost of the study to be
borne by a party other than the lessee. The Director shall make results
of any such study available to interested parties and to the public as
soon as practicable after the completion of the study and submission of
the results thereof.
(2) When the Director determines that measures are necessary, on the
basis of the results of the studies conducted in accordance with
paragraph (e)(1) of this section and other information available to and
identified by the Director, the lessee will be required to take
appropriate measures to mitigate, avoid, or minimize the damage or
potential damage on which the suspension or temporary prohibition is
based. In choosing between alternative mitigation measures, the Director
will balance the cost of the required measures against the reduction or
potential reduction in damage or threat of damage or harm to life
(including fish and other aquatic life), to property, to any mineral
deposits (in areas leased or not leased), to the National security or
defense, or to the marine, coastal, or human environment. When deemed
appropriate by the Director, the lessee must submit to the Bureau of
Ocean Energy Management a revised Delineation, Testing, or Mining Plan
that incorporates the mitigation measures required by the Director.
(f)(1) If under the provisions of paragraphs (b)(2), (3), and (4) of
this section, the Director, with respect to any lease, directs the
suspension of production or

[[Page 322]]

other operations on the entire leasehold, no payment of rental or
minimum royalty shall be due for or during the period of the directed
suspension and the time for the lessee specify royalty free period of a
period of reduced royalty pursuant to 30 CFR 581.28(b) will be extended
for the period of directed suspension. If under the provisions of
paragraphs (b)(2), (3), and (4) of this section the Director, with
respect to a lease on which there has been no production, directs the
suspension of operations on the entire leasehold, no payment of rental
shall be due during the period of the directed suspension.
(2) If under the provisions of this section, the Director grants the
request of a lessee for a suspension of production or other operations,
the lessee's obligations to pay rental, minimum royalty, or royalty
shall continue to apply during the period of the approved suspension,
unless the Director's approval of the lessee's request for suspension
authorizes the payment of a lesser amount during the period of approved
suspension. If under the provision of this section, the Director grants
a lessee's request for a suspension of production or other operations
for a lease which includes provisions for a time period which the lessee
may specify during which production from the leasehold would be royalty
free or subject to a reduced royalty obligation pursuant to 30 CFR
581.28(b), the time during which production from a leasehold may be
royalty free or subject to a reduced royalty obligation shall not be
extended unless the Director's approval of the suspension specifies
otherwise.
(3) If the lease anniversary date falls within a period of
suspension for which no rental or minimum royalty payments are required
under paragraph (a) of this section, the prorated rentals or minimum
royalties are due and payable as of the date the suspension period
terminates. These amounts shall be computed and notice thereof given the
lessee. The lessee shall pay the amount due within 30 days after receipt
of such notice. The anniversary date of a lease shall not change by
reason of any period of lease suspension or rental or royalty relief
resulting therefrom.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36153, June 6, 2016]

Sec. 282.14 Noncompliance, remedies, and penalties.

[[Page 323]]

within which such action must be taken.
(c) Failure of a lessee to take the actions specified in the notice
of noncompliance within the time limit specified shall be grounds for a
suspension of operations and other appropriate actions, including but
not limited to the assessment of a civil penalty of up to $40,000 per
day for each violation that is not corrected within the time period
specified (43 U.S.C. 1350(b)).
(d) Whenever the Director determines that a violation of or failure
to comply with any provision of the Act; or any provision of a lease,
license, or permit issued pursuant to the Act; or any provision of any
regulation promulgated under the Act probably occurred and that such
apparent violation continued beyond notice of the violation and the
expiration of the reasonable time period allowed for corrective action,
the Director shall follow the procedures concerning remedies and
penalties in subpart N, Remedies and Penalties, of 30 CFR part 250 to
determine and assess an appropriate penalty.
(e) The remedies and penalties prescribed in this section shall be
concurrent and cumulative, and the exercise of one shall not preclude
the exercise of the other. Further, the remedies and penalties
prescribed in this section shall be in addition to any other remedies
and penalties afforded by any other law or regulation (43 U.S.C.
1350(e)).

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36154, June 6, 2016]

Sec. 282.15 [Reserved]

Subpart C_Obligations and Responsibilities of Lessees

Sec. 282.20 [Reserved]

Sec. 282.21 Plans, general.

(a)-(d) [Reserved]
(e) Leasehold activities shall be carried out with due regard to
conservation of resources, paying particular attention to the wise
management of OCS mineral resources, minimizing waste of the leased
resource(s) in mining and processing, and preventing damage to unmined
parts of the mineral deposit and other resources of the OCS.

Sec. Sec. 282.22-282.26 [Reserved]

Sec. 282.27 Conduct of operations.

(a) The lessee shall conduct all exploration, testing, development,
and production activities and other operations in a safe and workmanlike
manner and shall maintain equipment in a manner which assures the
protection of the lease and its improvements, the health and safety of
all persons, and the conservation of property, and the environment.
(b) Nothing in this part shall preclude the use of new or
alternative technologies, techniques, procedures, equipment, or
activities, other than those prescribed in the regulations of this part,
if such other technologies, techniques, procedures, equipment, or
activities afford a degree of protection, safety, and performance equal
to or better than that intended to be achieved by the regulations of
this part, provided the lessee obtains the written approval of the
Director prior to the use of such new or alternative technologies,
techniques, procedures, equipment, or activities.
(c) The lessee shall immediately notify the Director when there is a
death or serious injury; fire, explosion, or other hazardous event which
threatens damage to life, a mineral deposit, or equipment; spills of
oil, chemical reagents, or other liquid pollutants which could cause
pollution; or damage to aquatic life or the environment associated with
operations on the lease. As soon as practical, the lessee shall file a
detailed report on the event and action(s) taken to control the
situation and to mitigate any further damage.
(d)(1) Lessees shall provide means, at all reasonable hours either
day or night, for the Director to inspect or investigate the conditions
of the operation and to determine whether applicable regulations; terms
and conditions of the lease; and the requirements of the approved
Delineation, Testing, or Mining Plan are being met.
(2) A lessee shall, on request by the Director, furnish food,
quarters, and

[[Page 324]]

transportation for BSEE representatives to inspect its facilities. Upon
request, you will be reimbursed by BSEE for the actual costs that you
incur as a result of providing transportation to BSEE representatives.
In addition, you will be reimbursed for the actual costs that you incur
for providing food and quarters for a BSEE representative's stay of more
than 12 hours. You must submit an invoice for reimbursement within 90
days of the inspection.
(e) Mining and processing vessels, platforms, structures, artificial
islands, and mobile drilling units which have helicopter landing
facilities shall be identified with at least one sign using letters and
figures not less than 12 inches in height. Signs for structures without
helicopter landing facilities shall be identified with at least one sign
using letters and figures not less than 3 inches in height. Signs shall
be affixed at a location that is visible to approaching traffic and
shall contain the following information which may be abbreviated:
(1) Name of the lease operator;
(2) The area designation based on Official OCS Protraction Diagrams;
(3) The block number in which the facility is located; and
(4) Vessel, platform, structure, or rig name.
(f)(1) Drilling. (i) When drilling on lands valuable or potentially
valuable for oil and gas or geopressured or geothermal resources,
drilling equipment shall be equipped with blowout prevention and control
devices acceptable to the Director before penetrating more than 500 feet
unless a different depth is specified in advance by the Director.
(ii) In cases where the Director determines that there is sufficient
likelihood of encountering pressurized hydrocarbons, the Director may
require that the lessee comply with all or portions of the requirements
in part 250, subpart D, of this title.
(iii) Before drilling any hole which may penetrate an aquifer, the
lessee shall follow the procedures included in the approved plan for the
penetration and isolation of the aquifer during the drilling operation,
during use of the hole, and for subsequent abandonment of the hole.
(iv) Cuttings from holes drilled on the lease shall be disposed of
and monitored in accordance with the approved plan.
(v) The use of muds in drilling holes on the lease and their
subsequent disposition shall be according to the approved plan.
(2) All drill holes which are susceptible to logging shall be
logged, and the lessee shall prepare a detailed lithologic log of each
drill hole. Drill holes which are drilled deeper than 500 feet shall be
drilled in a manner which permits logging. Copies of logs of cores and
cuttings and all in-hole surveys such as electronic logs, gamma ray
logs, neutron density logs, and sonic logs shall be provided to the
Director.
(3) Drill holes for exploration, testing, development, or production
shall be properly plugged and abandoned to the satisfaction of the
Director in accordance with the approved plan and in such a manner as to
protect the surface and not endanger any operation; any freshwater
aquifer; or deposit of oil, gas, or other mineral substance.
(g) The use of explosives on the lease shall be in accordance with
the approved plan.
(h)(1) Any equipment placed on the seabed shall be designed to allow
its recovery and removal upon abandonment of leasehold activities.
(2) Disposal of equipment, cables, chains, containers, or other
materials into the ocean is prohibited.
(3) Materials, equipment, tools, containers, and other items used on
the OCS which are of such shape or configuration that they are likely to
snag or damage fishing devices shall be handled and marked as follows:
(i) All loose materials, small tools, and other small objects shall
be kept in a suitable storage area or a marked container when not in use
or in a marked container before transport over OCS waters;
(ii) All cable, chain, or wire segments shall be recovered after use
and securely stored;
(iii) Skid-mounted equipment, portable containers, spools or reels,
and drums shall be marked with the owner's name prior to use or
transport over OCS waters; and

[[Page 325]]

(iv) All markings must clearly identify the owner and must be
durable enough to resist the effects of the environmental conditions to
which they are exposed.
(4) Any equipment or material described in paragraphs (h)(2),
(h)(3)(ii), and (iii) of this section that is lost overboard shall be
recorded on the daily operations report of the facility and reported to
the Director and to the U.S. Coast Guard.
(i) Any bulk sampling or testing that is necessary to be conducted
prior to submission of a Mining Plan shall be in accordance with an
approved Testing Plan. The sale of any OCS minerals acquired under an
approved Testing Plan shall be subject to the payment of the royalty
specified in the lease to the United States.
(j) Installations and structures: (1) The lessee shall design,
fabricate, install, use, inspect, and maintain all installations and
structures, including platforms on the OCS, to assure the structural
integrity of all installations and structures for the safe conduct of
exploration, testing, mining, and processing activities considering the
specific environmental conditions at the location of the installation or
structure.
(2) All fixed or bottom-founded platforms or other structures, e.g.,
artificial islands shall be designed, fabricated, installed, inspected,
and maintained in accordance with the provisions of 30 CFR part 250,
subpart I.
(k) The lessee shall not produce any OCS mineral until the method of
measurement and the procedures for product valuation have been
instituted in accordance with the approved Testing or Mining Plan. The
lessee shall enter the weight or quantity and quality of each mineral
produced in accordance with 30 CFR 582.29.
(l) The lessee shall conduct OCS mineral processing operations in
accordance with the approved Testing or Mining Plan and use due
diligence in the reduction, concentration, or separation of mineral
substances by mechanical or chemical processes, by evaporation, or other
means, so that the percentage of concentrates or other mineral
substances are recovered in accordance with the practices approved in
the Testing or Mining Plan.
(m) No material shall be discharged or disposed of except in
accordance with the approved disposal practice and procedures contained
in the approved Delineation, Testing, or Mining Plan.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36154, June 6, 2016]

Sec. 282.28 Environmental protection measures.

(a)-(b) [Reserved]
(c)(1) The lessee shall monitor activities in a manner that develops
the data and information necessary to enable the Director to assess the
impacts of exploration, testing, mining, and processing activities on
the environment on and off the lease; develop and evaluate methods for
mitigating adverse environmental effects; validate assessments made in
previous environmental evaluations; and ensure compliance with lease and
other requirements for the protection of the environment.
(2) Monitoring of environmental effects shall include determination
of the spatial and temporal environmental changes induced by the
exploration, testing, development, production, and processing activities
on the flora and fauna of the sea surface, the water column, and/or the
seafloor.
(3) The Director may place observers onboard exploration, testing,
mining, and processing vessels; installations; or structures to ensure
that the provisions of the lease, the approved plan, and these
regulations are followed and to evaluate the effectiveness of the
approved monitoring and mitigation practices and procedures in
protecting the environment.
(4) The Director may order or the lessee may request a modification
of the approved monitoring program prior to the startup of testing
activities or commercial-scale recovery, and at other appropriate times
as necessary, to reflect accurately the proposed operations or to
incorporate the results of recent research or improved monitoring
techniques.
(5) [Reserved]
(6) When required, the monitoring plan will specify:

[[Page 326]]

(i) The sampling techniques and procedures to be used to acquire the
needed data and information;
(ii) The format to be used in analysis and presentation of the data
and information;
(iii) The equipment, techniques, and procedures to be used in
carrying out the monitoring program; and
(iv) The name and qualifications of person(s) designated to be
responsible for carrying out the environmental monitoring.
(d) Lessees shall develop and conduct their operations in a manner
designed to avoid, minimize, or otherwise mitigate environmental impacts
and to demonstrate the effectiveness of efforts to that end. Based upon
results of the monitoring program, the Director may specify particular
procedures for mitigating environmental impacts.
(e) [Reserved]

Sec. Sec. 282.29-282.30 [Reserved]

Sec. 282.31 Suspension of production or other operations.

A lessee may submit a request for a suspension of production or
other operations. The request shall include justification for granting
the requested suspension, a schedule of work leading to the initiation
or restoration of production or other operations, and any other
information the Director may require.

Subpart D_Payments

Sec. 282.40 [Reserved]

Sec. 282.41 Method of royalty calculation.

In the event that the provisions of royalty management regulations
in part 1206 of chapter XII do not apply to the specific commodities
produced under regulations in this part, the lessee shall comply with
procedures specified in the leasing notice.

Sec. 282.42 [Reserved]

Subpart E_Appeals

Sec. 282.50 Appeals.

See 30 CFR part 290 for instructions on how to appeal any order or
decision that we issue under this part.

PART 285 [RESERVED]

[[Page 327]]

SUBCHAPTER C_APPEALS

PART 290_APPEAL PROCEDURES--Table of Contents

Subpart A_Bureau of Safety and Environmental Enforcement Appeal
Procedures

Sec.
290.1 What is the purpose of this subpart?
290.2 Who may appeal?
290.3 What is the time limit for filing an appeal?
290.4 How do I file an appeal?
290.5 Can I obtain an extension for filing my Notice of Appeal?
290.6 Are informal resolutions permitted?
290.7 Do I have to comply with the decision or order while my appeal is
pending?
290.8 How do I exhaust my administrative remedies?

Subpart B [Reserved]

Authority: 5 U.S.C. 305; 43 U.S.C. 1334.

Source: 76 FR 64462, Oct. 18, 2011, unless otherwise noted.

Subpart A_Bureau of Safety and Environmental Enforcement Appeal
Procedures

Sec. 290.1 What is the purpose of this subpart?

The purpose of this subpart is to explain the procedures for appeals
of Bureau of Safety and Environmental Enforcement (BSEE) decisions and
orders issued under 30 CFR chapter II.

Sec. 290.2 Who may appeal?

If you are adversely affected by a BSEE official's final decision or
order issued under 30 CFR chapter II, you may appeal that decision or
order to the Interior Board of Land Appeals (IBLA). Your appeal must
conform with the procedures found in this subpart and 43 CFR part 4,
subpart E.

Sec. 290.3 What is the time limit for filing an appeal?

You must file your appeal within 60 days after you receive BSEE's
final decision or order. The 60-day time period applies rather than the
time period provided in 43 CFR 4.411(a). A decision or order is received
on the date you sign a receipt confirming delivery or, if there is no
receipt, the date otherwise documented.

Sec. 290.4 How do I file an appeal?

For your appeal to be filed, BSEE must receive all of the following
within 60 days after you receive the decision or order:
(a) A written Notice of Appeal together with a copy of the decision
or order you are appealing in the office of the BSEE officer that issued
the decision or order. You cannot extend the 60-day period for that
office to receive your Notice of Appeal; and
(b) A nonrefundable processing fee of $150 paid with the Notice of
Appeal.
(1) You must pay electronically through the Fees for Services page
on the BSEE Web site at http://www.bsee.gov, and you must include a copy
of the Pay.gov confirmation receipt page with your Notice of Appeal.
(2) You cannot extend the 60-day period for payment of the
processing fee.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36154, June 6, 2016]

Sec. 290.5 Can I obtain an extension for filing my Notice of Appeal?

You cannot obtain an extension of time to file the Notice of Appeal.
See 43 CFR 4.411(c).

Sec. 290.6 Are informal resolutions permitted?

(a) You may seek informal resolution with the issuing officer's next
level supervisor during the 60-day period established in Sec. 290.3.
(b) Nothing in this subpart precludes resolution by settlement of
any appeal or matter pending in the administrative process after the 60-
day period established in Sec. 290.3.

Sec. 290.7 Do I have to comply with the decision or order
while my appeal is pending?

(a) The decision or order is effective during the 60-day period for
filing an appeal under Sec. 290.3 unless:
(1) BSEE notifies you that the decision or order, or some portion of
it, is suspended during this period because there is no likelihood of
immediate and

[[Page 328]]

irreparable harm to human life, the environment, any mineral deposit, or
property; or
(2) You post a surety bond under 30 CFR 250.1409 pending the appeal
challenging an order to pay a civil penalty.
(b) This section applies rather than 43 CFR 4.21(a) for appeals of
BSEE orders.
(c) After you file your appeal, IBLA may grant a stay of a decision
or order under 43 CFR 4.21(b); however, a decision or order remains in
effect until IBLA grants your request for a stay of the decision or
order under appeal.

Sec. 290.8 How do I exhaust my administrative remedies?

(a) If you receive a decision or order issued under chapter II,
subchapter B, you must appeal that decision or order to IBLA under 43
CFR part 4, subpart E to exhaust administrative remedies.
(b) This section does not apply if the Assistant Secretary for Land
and Minerals Management or the IBLA makes a decision or order
immediately effective notwithstanding an appeal.

Subpart B [Reserved]

PART 291_OPEN AND NONDISCRIMINATORY ACCESS TO OIL AND GAS PIPELINES
UNDER THE OUTER CONTINENTAL SHELF LANDS ACT--Table of Contents

Sec.
291.1 What is BSEE's authority to collect information?
291.100 What is the purpose of this part?
291.101 What definitions apply to this part?
291.102 May I call the BSEE Hotline to informally resolve an allegation
that open and nondiscriminatory access was denied?
291.103 May I use alternative dispute resolution (ADR) to informally
resolve an allegation that and nondiscriminatory access was
denied?
291.104 Who may file a complaint or a third-party brief?
291.105 What must a complaint contain?
291.106 How do I file a complaint?
291.107 How do I answer a complaint?
291.108 How do I pay the processing fee?
291.109 Can I ask for a fee waiver or a reduced processing fee?
291.110 Who may BSEE require to produce information?
291.111 How does BSEE treat the confidential information I provide?
291.112 What process will BSEE follow in rendering a decision on whether
a grantee or transporter has provided open and
nondiscriminatory access?
291.113 What actions may BSEE take to remedy denial of open and
nondiscriminatory access?
291.114 How do I appeal to the IBLA?
291.115 How do I exhaust administrative remedies?

Authority: 31 U.S.C. 9701, 43 U.S.C. 1334.

Source: 76 FR 64462, Oct. 18, 2011, unless otherwise noted.

Sec. 291.1 What is BSEE's authority to collect information?

(a) The Office of Management and Budget (OMB) has approved the
information collection requirements in this part under 44 U.S.C. 3501 et
seq., and assigned OMB Control Number 1014-0012.
(b) An agency may not conduct or sponsor, and you are not required
to respond to, a collection of information unless it displays a
currently valid OMB control number.
(c) We use the information collected to determine whether or not the
shipper has been denied open and nondiscriminatory access to Outer
Continental Shelf (OCS) pipelines as sections of 5(e) and (f) of the OCS
Lands Act (OCSLA) require.
(d) Respondents are companies that ship or transport oil and gas
production across the OCS. Responses are required to obtain or retain
benefits. We will protect information considered proprietary under
applicable law.
(e) Send comments regarding any aspect of the collection of
information under this part, including suggestions for reducing the
burden, to the Information Collection Clearance Officer, Bureau of
Safety and Environmental Enforcement, 45600 Woodland Road, Sterling, VA
20166.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36154, June 6, 2016]

Sec. 291.100 What is the purpose of this part?

This part:
(a) Explains the procedures for filing a complaint with the
Director, Bureau of Safety and Environmental Enforcement (BSEE) alleging
that a grantee or

[[Page 329]]

transporter has denied a shipper of production from the OCS open and
nondiscriminatory access to a pipeline;
(b) Explains the procedures BSEE will employ to determine whether
violations of the requirements of the OCSLA have occurred, and to remedy
any violations; and
(c) Provides for alternative informal means of resolving pipeline
access disputes through either Hotline-assisted procedures or
alternative dispute resolution (ADR).

Sec. 291.101 What definitions apply to this part?

As used in this part:
Accessory means a platform, a major subsea manifold, or similar
subsea structure attached to a right-of-way (ROW) pipeline to support
pump stations, compressors, manifolds, etc. The site used for an
accessory is part of the pipeline ROW grant.
Appurtenance means equipment, device, apparatus, or other object
attached to a horizontal component or riser. Examples include anodes,
valves, flanges, fittings, umbilicals, subsea manifolds, templates,
pipeline end modules (PLEMs), pipeline end terminals (PLETs), anode
sleds, other sleds, and jumpers (other than jumpers connecting subsea
wells to manifolds).
FERC pipeline means any pipeline within the jurisdiction of the
Federal Energy Regulatory Commission (FERC) under the Natural Gas Act,
15 U.S.C. 717-717z, or the Interstate Commerce Act, 42 U.S.C. 7172(a)
and (b).
Grantee means any person to whom BSEE has issued an oil or gas
pipeline permit, license, easement, right-of-way, or other grant of
authority for transportation on or across the OCS under 30 CFR part 250,
subpart J, or 43 U.S.C. 1337(p), and any person who has an assignment of
a permit, license, easement, right-of-way or other grant of authority,
or who has an assignment of any rights subject to any of those grants of
authority under 30 CFR part 250, subpart J or 43 U.S.C. 1337(p).
IBLA means the Interior Board of Land Appeals.
OCSLA pipeline means any oil or gas pipeline for which BSEE has
issued a permit, license, easement, right-of-way, or other grant of
authority.
Outer Continental Shelf means all submerged lands lying seaward and
outside of the area of lands beneath navigable waters as defined in
section 2 of the Submerged Lands Act (43 U.S.C. 1301) and of which the
subsoil and seabed appertain to the United States and are subject to its
jurisdiction and control.
Party means any person who files a complaint, any person who files
an answer, and BSEE.
Person means an individual, corporation, government entity,
partnership, association (including a trust or limited liability
company), consortium, or joint venture (when established as a separate
entity).
Pipeline is the piping, risers, accessories and appurtenances
installed for transportation of oil and gas.
Serve means personally delivering a document to a person, or sending
a document by U.S. mail or private delivery services that provide proof
of delivery (such as return receipt requested) to a person.
Shipper means a person who contracts or wants to contract with a
grantee or transporter to transport oil or gas through the grantee's or
transporter's pipeline.
Transportation means, for purposes of this part only, the movement
of oil or gas through an OCSLA pipeline.
Transporter means, for purposes of this part only, any person who
owns or operates an OCSLA oil or gas pipeline.

Sec. 291.102 May I call the BSEE Hotline to informally resolve
an allegation that open and nondiscriminatory access was denied?

Before filing a complaint under Sec. 291.106, you may attempt to
informally resolve an allegation concerning open and nondiscriminatory
access by calling the toll-free BSEE Pipeline Open Access Hotline at 1-
888-232-1713.
(a) BSEE Hotline staff will informally seek information needed to
resolve the dispute. BSEE Hotline staff will attempt to resolve disputes
without litigation or other formal proceedings. The Hotline staff will
not attempt to resolve matters that are before BSEE or FERC in docketed
proceedings.

[[Page 330]]

(b) BSEE Hotline staff may provide information to you and give
informal oral advice. The advice given is not binding on BSEE, the
Department of the Interior (DOI), or any other person.
(c) To the extent permitted by law, the BSEE Hotline staff will
treat all information it obtains as non-public and confidential.
(d) You may call the BSEE Hotline anonymously.
(e) If you contact the BSEE Hotline, you may file a complaint under
this part if discussions assisted by BSEE Hotline staff are unsuccessful
at resolving the matter.
(f) You may terminate use of the BSEE Hotline procedure at any time.

Sec. 291.103 May I use alternative dispute resolution (ADR) to informally
resolve an allegation that open and nondiscriminatory access was denied?

You may ask to use ADR either before or after you file a complaint.
To make a request, call the BSEE at 1-888-232-1713 or write to us at the
following address: Director, Bureau of Safety and Environmental
Enforcement, Attention: Office of Policy and Analysis, 1849 C Street,
NW., Mail Stop 5438, Washington, DC 20240-0001.
(a) You may request that ADR be administered by:
(1) A contracted ADR provider agreed to by all parties;
(2) The Department's Office of Collaborative Action and Dispute
Resolution (CADR); or
(3) BSEE staff trained in ADR and certified by the CADR.
(b) Each party must pay its respective share of all costs and fees
associated with any contracted or Departmental ADR provider. For
purposes of this section, BSEE is not a party in an ADR proceeding.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36154, June 6, 2016]

Sec. 291.104 Who may file a complaint or a third-party brief?

(a) You may file a complaint under this subpart if you are a shipper
and you believe that you have been denied open and nondiscriminatory
access to an OCSLA pipeline that is not a FERC pipeline.
(b) Any person that believes its interests may be affected by
precedents established by adjudication of complaints under this rule may
submit a brief to BSEE. The brief must be served following the procedure
set out in Sec. 291.107. After considering the brief, it is within
BSEE's discretion as to whether BSEE may:
(1) Address the brief in its decision;
(2) Not address the brief in its decision; or
(3) Include the submitter of the brief in the proceeding as a party.

Sec. 291.105 What must a complaint contain?

For purposes of this subpart, a complaint means a comprehensive
written brief stating the legal and factual basis for the allegation
that a shipper was denied open and nondiscriminatory access, together
with supporting material. A complaint must:
(a) Clearly identify the action or inaction which is alleged to
violate 43 U.S.C. 1334(e) or (f)(1)(A);
(b) Explain how the action or inaction violates 43 U.S.C. 1334(e) or
(f)(1)(A);
(c) Explain how the action or inaction affects your interests,
including practical, operational, or other non-financial impacts;
(d) Estimate any financial impact or burden;
(e) State the specific relief or remedy requested; and
(f) Include all documents that support the facts in your complaint
including, but not limited to, contracts and any affidavits that may be
necessary to support particular factual allegations.

Sec. 291.106 How do I file a complaint?

To file a complaint under this part, you must:
(a) File your complaint with the Director, Bureau of Safety and
Environmental Enforcement at the following address: Director, Bureau of
Safety and Environmental Enforcement, Attention: Office of Policy and
Analysis, 1849 C Street, NW., Mail Stop 5438, Washington, DC 20240-0001;
and
(b) Include a nonrefundable processing fee of $7,500 under Sec.
291.108(a) or

[[Page 331]]

a request for reduction or waiver of the fee under Sec. 291.109(a); and
(c) Serve your complaint on all persons named in the complaint. If
you make a claim under Sec. 291.111 for confidentiality, serve the
redacted copy and proposed form of a protective agreement on all persons
named in the complaint.
(d) Complaints shall not be filed later than 2 years from the time
of the alleged access denial. If the complaint is filed later than 2
years from the time of the alleged access denial, the BSEE Director will
not consider the complaint and the case will be closed.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36154, June 6, 2016]

Sec. 291.107 How do I answer a complaint?

(a) If you have been served a complaint under Sec. 291.106, you
must file an answer within 60 days of receiving the complaint. If you
miss this deadline, BSEE may disregard your answer. We consider your
answer to be filed when the BSEE Director receives it at the following
address: Director, Bureau of Safety and Environmental Enforcement,
Attention: Office of Policy and Analysis, 1849 C Street, NW., Mail Stop
5438, Washington, DC 20240-0001.
(b) For purposes of this paragraph, an answer means a comprehensive
written brief stating the legal and factual basis refuting the
allegations in the complaint, together with supporting material. You
must:
(1) Attach to your answer a copy of the complaint or reference the
assigned BSEE docket number (you may obtain the docket number by calling
the Office of Policy and Analysis at (202) 208-1901);
(2) Explain in your answer why the action or inaction alleged in the
complaint does not violate 43 U.S.C. 1334(e) or (f)(1)(A);
(3) Include with your answer all documents in your possession or
that you can otherwise obtain that support the facts in your answer
including, but not limited to, contracts and any affidavits that may be
necessary to support particular factual allegations; and
(4) Provide a copy of your answer to all parties named in the
complaint including the complainant. If you make a claim under Sec.
291.111 for confidentiality, serve the redacted copy and proposed form
of a protective agreement to all parties named in the complaint,
including the complainant.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36154, June 6, 2016]

Sec. 291.108 How do I pay the processing fee?

(a) You must pay the processing fee electronically through the Fees
for Services page on the BSEE Web site at http://www.bsee.gov, and you
must include a copy of the Pay.gov confirmation receipt page with your
complaint.
(b) You must include with the payment:
(1) Your taxpayer identification number;
(2) Your payor identification number, if applicable; and
(3) The complaint caption, or any other applicable identification of
the complaint you are filing.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36154, June 6, 2016]

Sec. 291.109 Can I ask for a fee waiver or a reduced processing fee?

(a) BSEE may grant a fee waiver or fee reduction in extraordinary
circumstances. You may request a waiver or reduction of your fee by:
(1) Sending a written request to the BSEE Office of Policy and
Analysis when you file your complaint; and
(2) Demonstrating in your request that you are unable to pay the fee
or that payment of the full fee would impose an undue hardship upon you.
(b) The BSEE Office of Policy and Analysis will send you a written
decision granting or denying your request for a fee waiver or a fee
reduction.
(1) If we grant your request for a fee reduction, you must pay the
reduced processing fee within 30 days of the date you receive our
decision.
(2) If we deny your request, you must pay the entire processing fee
within 30 days of the date you receive the decision.
(3) BSEE's decision granting or denying a fee waiver or reduction is
final for the Department.

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36154, June 6, 2016]

[[Page 332]]

Sec. 291.110 Who may BSEE require to produce information?

(a) BSEE may require any lessee, operator of a lease or unit,
shipper, grantee, or transporter to provide information that BSEE
believes is necessary to make a decision on whether open access or
nondiscriminatory access was denied.
(b) If you are a party and fail to provide information BSEE requires
under paragraph (a) of this section, BSEE may:
(1) Assess civil penalties under 30 CFR part 250, subpart N;
(2) Dismiss your complaint or consider your answer incomplete; or
(3) Presume the required information is adverse to you on the
factual issues to which the information is relevant.
(c) If you are not a party to a complaint and fail to provide
information BSEE requires under paragraph (a) of this section, BSEE may
assess civil penalties under 30 CFR part 250, subpart N.

Sec. 291.111 How does BSEE treat the confidential information I provide?

(a) Any person who provides documents under this part in response to
a request by BSEE to inform a decision on whether open access or
nondiscriminatory access was denied may claim that some or all of the
information contained in a particular document is confidential. If you
claim confidential treatment, then when you provide the document to BSEE
you must:
(1) Provide a complete unredacted copy of the document and indicate
on that copy that you are making a request for confidential treatment
for some or all of the information in the document.
(2) Provide a statement specifying the specific statutory
justification for nondisclosure of the information for which you claim
confidential treatment. General claims of confidentiality are not
sufficient. You must furnish sufficient information for BSEE to make an
informed decision on the request for confidential treatment.
(3) Provide a second copy of the document from which you have
redacted the information for which you wish to claim confidential
treatment. If you do not submit a second copy of the document with the
confidential information redacted, BSEE may assume that there is no
objection to public disclosure of the document in its entirety.
(b) In making data and information you submit available to the
public, BSEE will not disclose documents exempt from disclosure under
the Freedom of Information Act (5 U.S.C. 552) and will follow the
procedures set forth in the implementing regulations at 43 CFR part 2 to
give submitters an opportunity to object to disclosure.
(c) BSEE retains the right to make the determination with regard to
any claim of confidentiality. BSEE will notify you of its decision to
deny a claim, in whole or in part, and, to the extent permitted by law,
will give you an opportunity to respond at least 10 days before its
public disclosure.

Sec. 291.112 What process will BSEE follow in rendering a decision
on whether a grantee or transporter has provided open
and nondiscriminatory access?

BSEE will begin processing a complaint upon receipt of a processing
fee or granting a waiver of the fee. The BSEE Director will review the
complaint, answer, and other information, and will serve all parties
with a written decision that:
(a) Makes findings of fact and conclusions of law; and
(b) Renders a decision determining whether the complainant has been
denied open and nondiscriminatory access.

Sec. 291.113 What actions may BSEE take to remedy denial of open
and nondiscriminatory access?

If the BSEE Director's decision under Sec. 291.112 determines that
the grantee or transporter has not provided open access or
nondiscriminatory access, then the decision will describe the actions
BSEE will take to require the grantee or transporter to remedy the
denial of open access or nondiscriminatory access. The remedies BSEE
would require must be consistent with BSEE's statutory authority,
regulations, and any limits thereon due to Congressional delegations to
other agencies. Actions BSEE may take include, but are not limited to:

[[Page 333]]

(a) Ordering grantees and transporters to provide open and
nondiscriminatory access to the complainant;
(b) Assessing civil penalties of up to $10,000 per day under 30 CFR
part 250, subpart N, for failure to comply with a BSEE order to provide
open access or nondiscriminatory access. Penalties will begin to accrue
60 days after the grantee or transporter receives the order to provide
open and nondiscriminatory access if it has not provided such access by
that time. However, if BSEE determines that requiring the construction
of facilities would be an appropriate remedy under the OCSLA, penalties
will begin to accrue 10 days after conclusion of diligent construction
of needed facilities or 60 days after the grantee or transporter
receives the order to provide open and nondiscriminatory access,
whichever is later, if it has not provided such access by that time;
(c) Requesting the Attorney General to institute a civil action in
the appropriate United States District Court under 43 U.S.C. 1350(a) for
a temporary restraining order, injunction, or other appropriate remedy
to enforce the open and nondiscriminatory access requirements of 43
U.S.C. 1334(e) and (f)(1)(A); or
(d) Initiating a proceeding to forfeit the right-of-way grant under
43 U.S.C. 1334(e).

Sec. 291.114 How do I appeal to the IBLA?

Any party, except as provided in Sec. 291.115(b), adversely
affected by a decision of the BSEE Director under this part may appeal
to the Interior Board of Land Appeals (IBLA) under the procedures in 43
CFR part 4, subpart E.

Sec. 291.115 How do I exhaust administrative remedies?

(a) If the BSEE Director issues a decision under this part but does
not expressly make the decision effective upon issuance, you must appeal
the decision to the IBLA under 43 CFR part 4 to exhaust administrative
remedies. Such decision will not be effective during the time in which a
person adversely affected by the BSEE Director's decision may file a
notice of appeal with the IBLA, and the timely filing of a notice of
appeal will suspend the effect of the decision pending the decision on
appeal.
(b) This section does not apply if a decision was made effective by:
(1) The BSEE Director; or
(2) The Assistant Secretary for Land and Minerals Management.

PARTS 292 299 [RESERVED]

[[Page 335]]

CHAPTER IV--GEOLOGICAL SURVEY, DEPARTMENT OF THE INTERIOR

--------------------------------------------------------------------
Part Page
400

[Reserved]

401 State Water Research Institute Program...... 337
402 Water-Resources Research Program and the
Water-Resources Technology Development
Program................................. 342
403-499

[Reserved]

[[Page 337]]

PART 400 [RESERVED]

PART 401_STATE WATER RESEARCH INSTITUTE PROGRAM--Table of Contents

Subpart A_General

Sec.
401.1 Purpose.
401.2 Delegation of authority.
401.3 Definitions.
401.4 Information collection.
401.5 [Reserved]

Subpart B_Designation of Institutes; Institute Programs

401.6 Designation of institutes.
401.7 Programs of institutes.
401.8-401.10 [Reserved]

Subpart C_Application and Management Procedures

401.11 Applications for grants.
401.12 Program management.
401.13-401.18 [Reserved]

Subpart D_Reporting

401.19 Reporting procedures.
401.20-401.25 [Reserved]

Subpart E_Evaluation

401.26 Evaluation of institutes.

Authority: 42 U.S.C. 10303.

Source: 50 FR 23114, May 31, 1985, unless otherwise noted.

Subpart A_General

Sec. 401.1 Purpose.

The regulations in this part are issued pursuant to title I of the
Water Research Act of 1984 (Pub. L. 98-242, 98 Stat. 97) which
authorizes appropriations to, and confers authority upon, the Secretary
of the Interior to promote a national program of water-resources
research.

Sec. 401.2 Delegation of authority.

The State Water Research Institute Program, as authorized by section
104 of the Act, has been established as a component of the U.S.
Geological Survey (USGS). Secretary of the Interior has delegated to the
Director of the USGS authority to take the actions and make the
determinations that, under the Act, are the responsibility of the
Secretary.

Sec. 401.3 Definitions.

Act means the Water Resources Research Act of 1984 (Pub. L. 98-242,
98 Stat. 97).
Fiscal year means a 12-month period ending on September 30.
Director means the Director of the USGS or a designee.
Grant means the funds made available to an institute in a particular
fiscal year pursuant to section 104 of the Act and the regulations in
this chapter.
Grantee means the college or university at which an institute is
established.
Granting agency means the USGS.
Institute means a water resources research institute, center, or
equivalent agency established in accordance with Title I of the Act.
Region means any grouping of two or more institutes mutually chosen
by themselves to reflect a commonality of water-resources problems.
Scientists means individuals engaged in any professional discipline,
including the life, physical or social sciences, and engineers.
Secretary means the Secretary of the Interior or a designee.
State means each of the 50 States, the Commonwealth of Puerto Rico,
the Virgin Islands, the District of Columbia, Guam, American Samoa, the
Commonwealth of the Mariana Islands, and the Federated States of
Micronesia.

[50 FR 23114, May 31, 1985, as amended at 58 FR 27204, May 7, 1993]

Sec. 401.4 Information collection.

(a) The information collection requirements contained in sections
401.11 and 401.19 have been approved by the Office of Management and
Budget under 44 U.S.C. 3501 et seq. and assigned clearance number 1028-
0044. The information will be used to support water related research and
provide performance reports on accomplishments achieved under Pub. L.
98-242, 98 Stat. 97 (42 U.S.C. 10303). This information allows the
agency to determine compliance with the objectives and criteria of

[[Page 338]]

the grant programs. Response is mandatory in accordance with 30 CFR
401.11 and 401.19.
(b) Public reporting burden for the collection of information is
estimated to average 84 hours per response, including the time for
reviewing instructions, searching existing data sources, gathering and
maintaining the data needed, and completing and reviewing the collection
of information. Send comments regarding this burden estimate, or any
other suggestions for reducing the burden, to Paperwork Management
Officer, U.S. Geological Survey, Paperwork Management Section MS 208,
Reston, Virginia 22092 and the Office of Management and Budget,
Paperwork Reduction Project (1028-0044), Washington, DC 20503.

[58 FR 27204, May 7, 1993]

Sec. 401.5 [Reserved]

Subpart B_Designation of Institutes; Institute Programs

Sec. 401.6 Designation of institutes.

(a) As a condition of recognition as an established institute under
the provisions of this chapter, each institute shall provide to the
Director written evidence that it conforms to the requirements of
subsection 104(a) of the Act, in that:
(1) The institute is established at the college or university in the
State that was established in accordance with the Act of July 21, 1862
(12 Stat. 503; 7 U.S.C. 301ff), i.e., a ``land-grant'' institution, or;
(2) If established at some other institution, the institute is at a
college or university that has been designated by act of the legislature
for the purposes of the Act, or;
(3) If there is more than one ``land-grant'' institution in the
State, and no designation has been made according to paragraph (a)(2) of
this section, the institute has been established at the one such
institution designated by the Governor of the State to participate in
the program, or;
(4) The institute has been designated as an interstate or regional
institute by two or more cooperating States as provided in the Act.
(b) The certification of designation made pursuant to paragraph (a)
of this section shall originate following the issuance of these
regulations, be signed by the highest ranking officer of the college or
university at which the institute is established and be submitted to the
Director within 90 days of the effective date of these regulations. It
shall be accompanied either by the evidence of establishment under the
provisions of 30 CFR part 401 or by new evidence of establishment made
pursuant to these regulations.
(c) Any institute not previously established under the provisions of
the Water Resources Act of 1964 (Pub. L. 88-379, 78 Stat. 331) or the
Water Research and Development Act of 1978 (Pub. L. 95-467, 92 Stat.
1305) shall also, in addition to the annual program application
specified in Sec. 401.11 of this chapter, submit to the Director the
following information:
(1) Evidence of the appointment by the governing authority of the
college or university of an officer to receive and account for all funds
paid under the provisions of the Act and to make annual reports to the
granting agency on work accomplished; and
(2) A management plan for meeting the requirements of the evaluation
mandated by Sec. 401.26.

[50 FR 23114, May 31, 1985, as amended at 58 FR 27204, May 7, 1993]

Sec. 401.7 Programs of institutes.

(a) Release of grant funds to participating institutes is
conditioned on the ability of each receiving institute to plan, conduct,
or otherwise arrange for:
(1) Competent research, investigations, and experiments of either a
basic or practical nature, or both, in relation to water resources;
(2) Promotion of the dissemination and application of the results of
these efforts; and
(3) Assistance in the training of scientists in relevant fields of
endeavor to water resources through the research, investigations, and
experiments.
(b) Such research, investigations, experiments and training may
include:
(1) Aspects of the hydrologic cycle;
(2) Supply and demand;
(3) Demineralization of saline and other impaired waters;

[[Page 339]]

(4) Conservation and best use of available supplies of water and
methods of increasing such supplies;
(5) Water reuse;
(6) Depletion and degradation of ground-water supplies;
(7) Improvements in the productivity of water when used for
agricultural, municipal, and commercial purposes;
(8) The economic, legal, engineering, social, recreational,
biological, geographical, ecological, or other aspects of water
problems;
(9) Scientific information dissemination activities, including
identifying, assembling, and interpreting the results of scientific
research on water resources problems, and ;
(10) Providing means for improved communication of research results,
having due regard for the varying conditions and needs of the respective
States and regions.
(c) An institute shall cooperate closely with other colleges and
universities in the State that have demonstrated capabilities for
research, information dissemination and graduate training in the
development of its program. For purposes of financial management,
reporting and other research program management and administration
activities, the institutes shall be responsible for performance of the
activities of other participating institutions.
(d) Each institute shall cooperate closely with other institutes and
other research organizations in the region to increase the effectiveness
of the institutes, to coordinate their activities, and to avoid undue
duplication of effort.

Sec. Sec. 401.8-401.10 [Reserved]

Subpart C_Application and Management Procedures

Sec. 401.11 Applications for grants.

(a) Subject to the availability of appropriated funds, but not to
exceed a total of $10 million, an equal amount of dollars will be
available to each qualified institute in each fiscal year to assist it
in carrying out the purposes of the Act. If the full amount of the
appropriated funds is not obligated by the close of the fiscal year for
which they were appropriated, the remaining funds shall be made
available in the succeeding fiscal year to support competitively
selected research projects under the terms of section 104(g) of the Act.
Selection and approval of such projects shall be based on criteria to be
determined by the Director. Announcement of such criteria shall be made
by notice in the Federal Register. The granting agency may retain an
amount up to 15 percent of the total appropriation for administrative
costs.
(b) The granting agency will annually make available to qualified
institutes instructions for the submittal of applications for grants.
The instructions will include information pertinent only to a single
fiscal year, such as the closing date for applications and the amount of
funds initially available to each institute. They also will include
notification of the provisions and assurances necessary to ensure that
administration of the grant will be conducted in compliance with this
chapter and other Federal laws and regulations applicable to grants to
institutions of higher learning.
(c) In making its application for funds to which it is entitled
under the Act, each institute shall use and follow the standard form for
Federal assistance (SF 424, Federal Assistance). No preapplication is
required. The institute shall include in section IV of Standard Form 424
evidence that its application was:
(1) Developed in close consultation and collaboration with senior
personnel of the State's department of water resources or similar
agencies, other leading water resources officials within the State, and
interested members of the public;
(2) Coordinated with other institutes in the region for the purposes
of avoiding duplication of effort and encouraging regional cooperation
in research areas of water management, development, and conservation
that have a regional or national character; and
(3) Reviewed for technical merit of its research components by
qualified scientists.
(d) Each application shall further include:
(1) A financial plan relating expenditures to scheduled activity and
rate of effort to be expended and indicating

[[Page 340]]

the times at which there will be need for specified amounts of Federal
funds; and
(2) A description of the institute's arrangements for development,
administration, and technical oversight of the research program.
(e) Each annual program application is to include separately
identifiable proposals for conduct of research to meet the needs of the
State and region. Such proposals must set forth for each project:
(1) The nature, scope and objectives of the project to be
undertaken;
(2) Its importance to the State, region, or Nation; its relation to
other known research projects already completed or in progress; and the
anticipated applicability of the research results;
(3) The period during which it will be pursued;
(4) The names and qualifications of the senior professional
personnel who will direct and conduct the project;
(5) Its estimated costs, with a breakdown of the costs per year; and
(6) The extent of which it will provide opportunity for the training
of scientists.
(f) Each program application shall contain a plan for disseminating
information on the results of research and promoting their application.
Plans which require the use of grant funds shall contain:
(1) Definition of the topics for dissemination;
(2) Identification of the target audiences for dissemination;
(3) Strategies for accomplishing the dissemination;
(4) Duties and qualifications of the personnel to be involved;
(5) Estimated costs of each identifiable element of the plan; and
(6) Identification of cooperating entities.
(g) The application shall provide assurance that non-Federal dollars
will be available to share the costs of the proposed program. The
Federal funds are to be matched on a basis of no less than two non-
Federal dollars for each Federal dollar, unless this matching
requirement has been waived.
(h) The granting agency will evaluate the proposals for consistency
with the provisions of its instructions and this chapter and within no
more than 90 days request any revisions and additions necessary for such
consistency.

[50 FR 23114, May 31, 1985, as amended at 58 FR 27204, May 7, 1993]

Sec. 401.12 Program management.

(a) Upon approval of each fiscal year's proposed program, the
granting agency will transmit to the grantee an award which will
incorporate the application and assurances.
(b) The grant is effective and constitutes an obligation of Federal
funds in the amount and for the purpose stated in the award document at
the time of the Director's signature.
(c)(1) Acceptance of the award document certifies the grantee's
assurance that the grant will be administered in compliance with OMB
regulations, policies, guidelines, and requirements as described in:
(i) Circular No. A-21, revised, Cost Principles of Educational
Institutions;
(ii) Memorandum No. M-92-01, Coordination of Water Resources
Information;
(iii) Circular No. A-88, revised, Indirect Cost Rates, Audit and
Audit Follow-up at Educational Institutions;
(iv) Circular No. A-110, Uniform Administrative Requirements for
Grants and Agreements with Institutions of Higher Education, Hospitals
and other Nonprofit Organizations; and
(v) Circular No. A-124, Patents--Small Business Firms and Nonprofit
Organizations.
(2) Copies of the documents listed in paragraph (c)(1) of this
section shall be available from the granting agency.

[50 FR 23114, May 31, 1985, as amended at 58 FR 27204, May 7, 1993]

Sec. Sec. 401.13-401.18 [Reserved]

Subpart D_Reporting

Sec. 401.19 Reporting procedures.

(a) The institutes are encouraged to publish, as technical reports
or in the professional literature, the findings, results, and
conclusions relating to separately identifiable research projects
undertaken pursuant to the Act.

[[Page 341]]

(b) Each institute shall submit to the granting agency, by a date to
be specified in the award document, an annual program report which
provides:
(1) A statement concerning the relationship of the institute's
program to the water problems and issues of the State;
(2) A synopsis of the objectives, methods, and conclusions of each
project completed within the period covered;
(3) A progress report on each project continuing into the subsequent
fiscal year;
(4) Citations of all reports, papers, publications or other
communicable products resulting from each project completed or in
progress;
(5) A description of all activities undertaken for the purpose of
promoting the application of research results;
(6) A description of cooperative arrangements with other educational
institutions, State agencies, and others.
(c) One manuscript of reproducible quality and two copies of the
annual program report shall be furnished to the granting agency. One
copy of a complete report on the objectives, methods, and conclusions of
each research project shall be maintained by the institute and open to
inspection.
(d) Appropriate acknowledgment shall be given by institutes to the
granting agency's participation in financing activities carried out
under provisions of the Act. Such acknowledgment shall be included in
all reports, publications, news releases, and other information media
developed by institutes and others to publicize, describe, or report
upon accomplishments and activities of the program.
(e) An original and two copies of the final ``Financial Status
Report,'' SF 269, shall be furnished to the granting agency within 90
days of completion of the grant period.

Sec. Sec. 401.20-401.25 [Reserved]

Subpart E_Evaluation

Sec. 401.26 Evaluation of institutes.

(a) Within 2 years of the date of its certification according to the
provisions of Sec. 401.6, each institute will be evaluated for the
purpose of determining whether the national interest warrants its
continued support under the provisions of the Act. That determination
shall be based on:
(1) The quality and relevance of its water resources research as
funded under the Act;
(2) Its effectiveness as an institution for planning, conducting, or
arranging for research;
(3) Its demonstrated performance in making research results
available to users in the State and elsewhere; and
(4) Its demonstrated record in providing for the training of
scientists through student involvement in its research program.
(b) An evaluation team, selected by the granting agency on the basis
of the members' knowledge of water research and administration, shall
evaluate each institute, and may with the concurrence of the granting
agency, visit such institutes as it considers necessary. The team is to
include at least one individual from each of the following categories:
(1) Employees of the Department of the Interior;
(2) University faculty or other professionals with relevant
experience in the conduct of water resources research;
(3) Former directors of water research institutes; and
(4) University faculty or other professionals with relevant
experience in information transfer.
(c) The granting agency may request recommendations for team
selections from the National Research Council/National Academy of
Sciences and from other organizations whose members include the types of
individuals cited in paragraph (b) of this section.
(d) The granting agency shall, as an administrative cost, provide
the funds for travel and per diem expense of the team members, within
the maximum limits allowable under Federal travel regulations (41 CFR
subtitle F).
(e) The granting agency has the right to select dates for evaluation
visits, and notice of the team's visit shall be provided to the
institute being evaluated at least 60 days in advance.
(f) It shall be the responsibility of each institute to provide such
documentation of its activities and accomplishments as the granting
agency and

[[Page 342]]

evaluation team may reasonably request. The request for this
documentation shall be made at least 60 days prior to the due date of
its receipt.
(g) The team shall, within 90 days after completion of its
evaluation, submit a written report of its findings to the granting
agency for transmittal to the institute. If an institute is found to
have deficiencies in meeting the objectives of the Act, it shall be
allowed 1 year to correct them and to report such action to the granting
agency. The decision as to the institute's eligibility to receive
further funding will rest with the granting agency.
(h) After the initial evaluation, each institute shall be
reevaluated at least every 5 years.

[58 FR 27204, May 7, 1993]

PART 402_WATER-RESOURCES RESEARCH PROGRAM AND THE WATER-RESOURCES TECHNOLOGY
DEVELOPMENT PROGRAM--Table of Contents

Subpart A_General

Sec.
402.1 Purpose.
402.2 Delegation of authority.
402.3 Definitions.
402.4 Information collection.
402.5 [Reserved]

Subpart B_Description of Water-Resources Programs

402.6 Water-Resources Research Program.
402.7 Water-Resources Technology Development Program.
402.8-402.9 [Reserved]

Subpart C_Application, Evaluation, and Management Procedures

402.10 Research-project applications.
402.11 Technology-development project applications.
402.12 Evaluation of applications for grants and contracts.
402.13 Program management.
402.14 [Reserved]

Subpart D_Reporting

402.15 Reporting procedures.

Authority: Secs. 105 and 106, Pub. L. 98-242, 98 Stat. 97 (42 U.S.C.
10304 and 10305).

Source: 51 FR 20963, June 10, 1986, unless otherwise noted.

Subpart A_General

Sec. 402.1 Purpose.

The regulations in this part are issued pursuant to title I of the
Water Resources Research Act of 1984 (Pub. L. 98-242, 98 Stat. 97),
which authorizes appropriations to, and confers authority upon, the
Secretary of the Interior to promote national programs of water-
resources research and technology development.

Sec. 402.2 Delegation of authority.

The Water-Resources Research Program and the Water-Resources
Technology Development Program, as authorized by sections 105 and 106 of
the Act (42 U.S.C. 10304 and 10305), have been established as components
of the USGS. The Secretary of the Interior has delegated to the Director
of the USGS authority to take actions and make the determinations that,
under the Act, are the responsibility of the Secretary.

Sec. 402.3 Definitions.

(a) Grant is used in these rules as a generic term for a Federal
assistance award, including project grants and cooperative agreements.
(b) Act means the Water Resources Research Act of 1984 (Pub. L. 98-
242, 98 Stat. 97).
(c) Educational institution means any educational institution--
privately and/or publicly owned.
(d) Dollar-for-dollar matching grant means for each Federal dollar
provided to support the projects, a non-Federal dollar also must be
provided to the project.

Sec. 402.4 Information collection.

The information-collection requirements contained in sections
402.10, 402.11, and 402.15 have been approved by the OMB under 44 U.S.C.
3501 et seq. and assigned clearance number 1028-0046. The application
proposals being collected will contain technical information that will
be used by the USGS as a basis for selection and award of grants. The
progress reports being collected will contain a description of all work
accomplished and results achieved on each funded project and will enable
the USGS to carry out its

[[Page 343]]

oversight responsibilities and provide dissemination of technical
information.

Sec. 402.5 [Reserved]

Subpart B_Description of Water-Resources Programs

Sec. 402.6 Water-Resources Research Program.

(a) Subject to the availability of appropriated funds, the Water-
Resources Research Program will provide support, in the form of a
dollar-for-dollar matching grant, to educational institutions, private
foundations, private firms, individuals, and agencies of local or State
governments for research concerning any aspect of a water-resource
related problem deemed to be in the national interest. Federal agencies
are excluded from receiving matching grants. Grants may be awarded on
other than a dollar-for-dollar matching basis in cases where the USGS
determines that research on a high-priority subject is of a basic nature
that otherwise would not be undertaken.
(b) The types of research to be undertaken under this program are
listed below, without indication of priority:
(1) Aspects of the hydrologic cycle;
(2) Supply and demand for water;
(3) Demineralization of saline and other impaired waters;
(4) Conservation and best use of available supplies of water and
methods of increasing such supplies;
(5) Water reuse;
(6) Depletion and degradation of groundwater supplies;
(7) Improvements in the productivity of water when used for
agricultural, municipal, and commercial purposes; and
(8) The economic, legal, engineering, social, recreational,
biological, geographic, ecological, and other aspects of water problems.
(9) Scientific information-dissemination activities, including
identifying, assembling, and interpreting the results of scientific and
engineering research on water-resources problems.
(10) Providing means for improved communications of research
results, having due regard for the varying conditions and needs for the
respective States and regions.

Sec. 402.7 Water-Resources Technology Development Program.

(a) Subject to the availability of appropriated funds, the Water-
Resources Technology Development Program will provide funds in the form
of grants or contracts to educational institutions, private firms,
private foundations, individuals, and agencies of local or State
governments for technology development concerning any aspect of water-
related technology deemed to be of State, regional, and national
importance, including technology associated with improvement of waters
of impaired quality and the operation of test facilities. Federal
agencies are excluded from receiving grants or contracts. The types of
technology-development to be undertaken under this program shall include
paragraphs 1 through 10 of Sec. 402.6(b).
(b) The USGS may establish any condition for the matching of funds
by the recipient of any grant or cost-sharing under a contract under the
technology-development program which the USGS considers to be in the
best interest of the Nation.

Sec. Sec. 402.8-402.9 [Reserved]

Subpart C_Application, Evaluation, and Management Procedures

Sec. 402.10 Research-project applications.

(a) Only those applications for grants that are in response to and
meet the guidelines of specific USGS announcements will be considered
for funding appropriated for this program.
(b) The USGS program announcements will identify priorities,
matching requirements, particular areas of interest, criteria for
evaluation, OMB regulations as appropriate, assurances, closing date,
and proposal submittal instructions. Program announcements may also
include criteria for high-priority subjects of a basic nature that may
be funded on other than a dollar-for-dollar basis. Program announcements
will be distributed to names on the current USGS mailing list for the

[[Page 344]]

Water-Resources Research Program announcements, including new requests
received in response to published notices of upcoming program
announcements.
(c) Notification of the availability of the program announcement
will be published in the Commerce Business Daily and/or Federal
Register.
(d) The application for funds must be signed by an individual or
official authorized to commit the applicant and it must contain:
(1) A Standard Form 424 ``Federal Assistance,'' sections I and II
completed by applicant, used as the cover sheet for each proposal.
(2) A project summary of no more than one typed, single-spaced page
providing the following specific information:
(i) Identification of the water or water-related problems and the
problem-solution approach;
(ii) Identification of the proposed scientific contribution of the
problem solution;
(iii) Concise statement of the specific objectives of the project;
(iv) Identification of the approach to be used to accomplish the
work; and
(v) Identification of potential users of the proposed work.
(3) Narrative information, as specified in the published program
announcement, such as project title, project objectives, background
information, research tasks, methodology to conduct the research task,
the relevancy of the proposed project to water-resources problems,
qualifications of the principal investigators and their organizations,
and proposed budget with supporting information sufficient to allow
evaluation of costs.

Sec. 402.11 Technology-development project applications.

(a) Grant awards will be used to support those portions of the
program for which the principal purpose is other than as described in
Sec. 402.11(b). Program announcements and applications will be governed
by the same procedures provided in Sec. 402.10.
(b) If it is determined that the principal purpose of a planned
award (or awards) is to acquire goods or services for the direct benefit
or use of the Government, the action must be regarded as a procurement
contract. A competitive solicitation prepared in accordance with
applicable acquisition regulations will be issued to interested parties.
Notification of the availability of any contract solicitation will be
published in the Commerce Business Daily, unless waived in accordance
with Sec. 5.202 of the Federal Acquisition Regulation (FAR). Contracts
may be awarded without full and open competition only if justified in
accordance with FAR subpart 6.3.

Sec. 402.12 Evaluation of applications for grants and contracts.

(a) Grants. (1) Each grant application will receive technical
evaluations from Government and/or non-Government scientific or
engineering personnel. Utilizing the criteria for evaluation identified
in the applicable announcement, each reviewer will assign a technical
score.
(2) Grant applications with low technical ratings will be screened
out, and the remaining grant applications will be rank-ordered by review
panels.
(3) USGS program officials will compile a single, consolidated rank-
ordered list of the grant applications based on technical scoring,
program needs and published priorities, and the available Federal funds.
(b) Contracts. Proposals for contract awards will be evaluated by a
USGS panel. Contracts will be awarded according to procedures contained
in the FAR, the Department of the Interior Acquisition Regulation, and
in acquisition policy releases issued by the Department and by the USGS.

Sec. 402.13 Program management.

(a) After the conclusion of negotiations, the USGS will transmit a
grant or contract-award document, as appropriate, setting forth the
terms of the award.
(b) Grants. Recipients will be required to execute funded projects
in accordance with OMB Circulars governing cost principles,
administrative requirements, and audit, as applicable to their
organization type. In addition, OMB Circular A-67, Coordination of
Federal Activities in the Acquisition of Certain

[[Page 345]]

Water Data, is applicable to awards under these programs.
(c) Contracts. Administrative requirements for performance of
research contracts will be established in the contract clauses in
conformance with applicable procurement regulations and other interior
or USGS acquisition policy documents. OMB Circular A-67 will also apply
to some contract awards under this program.

Sec. 402.14 [Reserved]

Subpart D_Reporting

Sec. 402.15 Reporting procedures.

(a) Grantees or contractors will be required to submit the following
technical reports to the USGS address identified under the terms and
conditions of each award.
(1) Quarterly Technical Progress Report. This report shall include a
description of all work accomplished, results achieved, and any changes
that affect the project's scope of work, time schedule, and personnel
assignments.
(2) Draft Technical Completion Report. The draft report will be
required for review prior to submission of the final technical
completion report.
(3) Final Technical Completion Report. The final report and a
camera-ready copy shall be submitted to the USGS within 90 days after
the expiration date of the award and shall include a summary of all work
accomplished, results achieved, conclusions, and recommendations. The
camera-ready copy shall be prepared in a manner suitable for
reproduction by a photographic process. Format will be specified in the
terms and conditions of the award.
(4) Final Report Abstract. A complete Water-Resources Scientific
Information Center Abstract Form 102 and National Technical Information
Service Form 79 shall be submitted with the final report.
(b) Grantees or contractors will be required to submit financial,
administrative, and closeout reports as identified under the terms of
each award. Reporting requirements will conform to the procedures
described in the Departmental Manual of the Department of the Interior
at 505 DM 1-5.
(c) Contracts for technology-development projects may also require
delivery of hardware items produced and/or specifications, drawings,
test results, or other data describing the funded technology.

PARTS 403 499 [RESERVED]

[[Page 347]]

CHAPTER V--BUREAU OF OCEAN ENERGY MANAGEMENT, DEPARTMENT OF THE INTERIOR

--------------------------------------------------------------------

SUBCHAPTER A--MINERALS REVENUE MANAGEMENT
Part Page
500-519

[Reserved]

SUBCHAPTER B--OFFSHORE
550 Oil and gas and sulphur operations in the
Outer Continental Shelf................. 350
551 Geological and geophysical (G&G)
explorations of the Outer Continental
Shelf................................... 415
552 Outer Continental Shelf (OCS) Oil and Gas
Information Program..................... 429
553 Oil spill financial responsibility for
offshore facilities..................... 434
556 Leasing of sulphur or oil and gas and
bonding requirements in the Outer
Continental Shelf....................... 449
560 Outer Continental Shelf oil and gas leasing. 488
570 Nondiscrimination in the Outer Continental
Shelf................................... 496
580 Prospecting for minerals other than oil,
gas, and sulphur on the Outer
Continental Shelf....................... 497
581 Leasing of minerals other than oil, gas, and
sulphur in the Outer Continental Shelf.. 509
582 Operations in the Outer Continental Shelf
for minerals other than oil, gas, and
sulphur................................. 522
583 Negotiated noncompetitive agreements for the
use of Outer Continental Shelf sand,
gravel, and/or shell resources.......... 540
585 Renewable energy and alternate uses of
existing facilities on the Outer
Continental Shelf....................... 546
SUBCHAPTER C--APPEALS
590 Appeal procedures........................... 631
591-599

[Reserved]

[[Page 349]]

SUBCHAPTER A_MINERALS REVENUE MANAGEMENT

PARTS 500 519 [RESERVED]

[[Page 350]]

SUBCHAPTER B_OFFSHORE

PART 550_OIL AND GAS AND SULPHUR OPERATIONS IN THE OUTER CONTINENTAL SHELF--
Table of Contents

Subpart A_General

Authority and Definition of Terms

Sec.
550.101 Authority and applicability.
550.102 What does this part do?
550.103 Where can I find more information about the requirements in this
part?
550.104 How may I appeal a decision made under BOEM regulations?
550.105 Definitions.

Performance Standards

550.115 How do I determine well producibility?
550.116 How do I determine producibility if my well is in the Gulf of
Mexico?
550.117 How does a determination of well producibility affect royalty
status?
550.118 [Reserved]
550.119 Will BOEM approve subsurface gas storage?
550.120 What standards will BOEM use to regulate leases, rights-of-use
and easement, and rights-of-way?
550.121 What must I do to protect health, safety, property, and the
environment?
550.122 What effect does subsurface storage have on the lease term?
550.123 Will BOEM allow gas storage on unleased lands?

Fees

550.125 Service fees.
550.126 Electronic payment instructions.

Inspection of Operations

550.130 [Reserved]

Disqualification

550.135 What will BOEM do if my operating performance is unacceptable?
550.136 How will BOEM determine if my operating performance is
unacceptable?

Special Types of Approvals

550.140 When will I receive an oral approval?
550.141 May I ever use alternate procedures or equipment?
550.142 How do I receive approval for departures?
550.143 How do I designate an operator?
550.144 How do I designate a new operator when a designation of operator
terminates?
550.146 How do I designate an agent or a local agent?
550.147 Who is responsible for fulfilling leasehold obligations?

Right-of-Use and Easement

550.160 When will BOEM grant me a right-of-use and easement, and what
requirements must I meet?
550.161 What else must I submit with my application?
550.162 May I continue my right-of-use and easement after the
termination of any lease on which it is situated?
550.163 If I have a State lease, will BOEM grant me a right-of-use and
easement?
550.164 If I have a State lease, what conditions apply for a right-of-
use and easement?
550.165 If I have a State lease, what fees do I have to pay for a right-
of-use and easement?
550.166 If I have a State lease, what surety bond must I have for a
right-of-use and easement?

Primary Lease Requirements, Lease Term Extensions, and Lease
Cancellations

550.181 When may the Secretary cancel my lease and when am I compensated
for cancellation?
550.182 When may the Secretary cancel a lease at the exploration stage?
550.183 When may BOEM or the Secretary extend or cancel a lease at the
development and production stage?
550.184 What is the amount of compensation for lease cancellation?
550.185 When is there no compensation for a lease cancellation?

Information and Reporting Requirements

550.186 What reporting information and report forms must I submit?
550.187-550.193 [Reserved]
550.194 How must I protect archaeological resources?
550.195 [Reserved]
550.196 Reimbursements for reproduction and processing costs.
550.197 Data and information to be made available to the public or for
limited inspection.

References

550.198 [Reserved]
550.199 Paperwork Reduction Act statements--information collection.

Subpart B_Plans and Information

General Information

550.200 Definitions.

[[Page 351]]

550.201 What plans and information must I submit before I conduct any
activities on my lease or unit?
550.202 What criteria must the Exploration Plan (EP), Development and
Production Plan (DPP), or Development Operations Coordination
Document (DOCD) meet?
550.203 Where can wells be located under an EP, DPP, or DOCD?
550.204 When must I submit my IOP for proposed Arctic exploratory
drilling operations and what must the IOP include?
550.205 [Reserved]
550.206 How do I submit the IOP, EP, DPP, or DOCD?

Ancillary Activities

550.207 What ancillary activities may I conduct?
550.208 If I conduct ancillary activities, what notices must I provide?
550.209 What is the BOEM review process for the notice?
550.210 If I conduct ancillary activities, what reporting and data/
information retention requirements must I satisfy?

Contents of Exploration Plans (EP)

550.211 What must the EP include?
550.212 What information must accompany the EP?
550.213 What general information must accompany the EP?
550.214 What geological and geophysical (G&G) information must accompany
the EP?
550.215 What hydrogen sulfide (H2S) information must
accompany the EP?
550.216 What biological, physical, and socioeconomic information must
accompany the EP?
550.217 What solid and liquid wastes and discharges information and
cooling water intake information must accompany the EP?
550.218 What air emissions information must accompany the EP?
550.219 What oil and hazardous substance spills information must
accompany the EP?
550.220 If I propose activities in the Alaska OCS Region, what planning
information must accompany the EP?
550.221 What environmental monitoring information must accompany the EP?
550.222 What lease stipulations information must accompany the EP?
550.223 What mitigation measures information must accompany the EP?
550.224 What information on support vessels, offshore vehicles, and
aircraft you will use must accompany the EP?
550.225 What information on the onshore support facilities you will use
must accompany the EP?
550.226 What Coastal Zone Management Act (CZMA) information must
accompany the EP?
550.227 What environmental impact analysis (EIA) information must
accompany the EP?
550.228 What administrative information must accompany the EP?

Review and Decision Process for the EP

550.231 After receiving the EP, what will BOEM do?
550.232 What actions will BOEM take after the EP is deemed submitted?
550.233 What decisions will BOEM make on the EP and within what
timeframe?
550.234 How do I submit a modified EP or resubmit a disapproved EP, and
when will BOEM make a decision?
550.235 If a State objects to the EP's coastal zone consistency
certification, what can I do?

Content of Development and Production Plans (DPP) and Development
Operations Coordination Documents (DOCD)

550.241 What must the DPP or DOCD include?
550.242 What information must accompany the DPP or DOCD?
550.243 What general information must accompany the DPP or DOCD?
550.244 What geological and geophysical (G&G) information must accompany
the DPP or DOCD?
550.245 What hydrogen sulfide (H2S) information must
accompany the DPP or DOCD?
550.246 What mineral resource conservation information must accompany
the DPP or DOCD?
550.247 What biological, physical, and socioeconomic information must
accompany the DPP or DOCD?
550.248 What solid and liquid wastes and discharges information and
cooling water intake information must accompany the DPP or
DOCD?
550.249 What air emissions information must accompany the DPP or DOCD?
550.250 What oil and hazardous substance spills information must
accompany the DPP or DOCD?
550.251 If I propose activities in the Alaska OCS Region, what planning
information must accompany the DPP?
550.252 What environmental monitoring information must accompany the DPP
or DOCD?
550.253 What lease stipulations information must accompany the DPP or
DOCD?
550.254 What mitigation measures information must accompany the DPP or
DOCD?
550.255 What decommissioning information must accompany the DPP or DOCD?

[[Page 352]]

550.256 What related facilities and operations information must
accompany the DPP or DOCD?
550.257 What information on the support vessels, offshore vehicles, and
aircraft you will use must accompany the DPP or DOCD?
550.258 What information on the onshore support facilities you will use
must accompany the DPP or DOCD?
550.259 What sulphur operations information must accompany the DPP or
DOCD?
550.260 What Coastal Zone Management Act (CZMA) information must
accompany the DPP or DOCD?
550.261 What environmental impact analysis (EIA) information must
accompany the DPP or DOCD?
550.262 What administrative information must accompany the DPP or DOCD?

Review and Decision Process for the DPP or DOCD

550.266 After receiving the DPP or DOCD, what will BOEM do?
550.267 What actions will BOEM take after the DPP or DOCD is deemed
submitted?
550.268 How does BOEM respond to recommendations?
550.269 How will BOEM evaluate the environmental impacts of the DPP or
DOCD?
550.270 What decisions will BOEM make on the DPP or DOCD and within what
timeframe?
550.271 For what reasons will BOEM disapprove the DPP or DOCD?
550.272 If a State objects to the DPP's or DOCD's coastal zone
consistency certification, what can I do?
550.273 How do I submit a modified DPP or DOCD or resubmit a disapproved
DPP or DOCD?

Post-Approval Requirements for the EP, DPP, and DOCD

550.280 How must I conduct activities under the approved EP, DPP, or
DOCD?
550.281 What must I do to conduct activities under the approved EP, DPP,
or DOCD?
550.282 Do I have to conduct post-approval monitoring?
550.283 When must I revise or supplement the approved EP, DPP, or DOCD?
550.284 How will BOEM require revisions to the approved EP, DPP, or
DOCD?
550.285 How do I submit revised and supplemental EPs, DPPs, and DOCDs?

Conservation Information Documents (CID)

550.296 When and how must I submit a CID or a revision to a CID?
550.297 What information must a CID contain?
550.298 How long will BOEM take to evaluate and make a decision on the
CID?
550.299 What operations require approval of the CID?

Subpart C_Pollution Prevention and Control

550.300-550.301 [Reserved]
550.302 Definitions concerning air quality.
550.303 Facilities described in a new or revised Exploration Plan or
Development and Production Plan.
550.304 Existing facilities.

Subpart D_Leasing Maps and Diagrams

550.400 Leasing maps and diagrams.

Subparts E-I [Reserved]

Subpart J_Pipelines and Pipeline Rights of Way

550.1011 Bond requirements for pipeline right-of-way holders.

Subpart K_Oil and Gas Production Requirements

Well Tests and Surveys

550.1153 When must I conduct a static bottomhole pressure survey?

Classifying Reservoirs

550.1154 How do I determine if my reservoir is sensitive?
550.1155 What information must I submit for sensitive reservoirs?

Other Requirements

550.1165 What must I do for enhanced recovery operations?
550.1166 What additional reporting is required for developments in the
Alaska OCS Region?
550.1167 What information must I submit with forms and for approvals?

Subparts L-M [Reserved]

Subpart N_Outer Continental Shelf Civil Penalties

Outer Continental Shelf Lands Act Civil Penalties

550.1400 How does BOEM begin the civil penalty process?
550.1401 Index table.
550.1402 Definitions.
550.1403 What is the maximum civil penalty?
550.1404 Which violations will BOEM review for potential civil
penalties?
550.1405 When is a case file developed?
550.1406 When will BOEM notify me and provide penalty information?

[[Page 353]]

550.1407 How do I respond to the letter of notification?
550.1408 When will I be notified of the Reviewing Officer's decision?
550.1409 What are my appeal rights?

Federal Oil and Gas Royalty Management Act Civil Penalties Definitions

550.1450 What definitions apply to this subpart?

Penalties After a Period To Correct

550.1451 What may BOEM do if I violate a statute, regulation, order, or
lease term relating to a Federal oil and gas lease?
550.1452 What if I correct the violation?
550.1453 What if I do not correct the violation?
550.1454 How may I request a hearing on the record on a Notice of
Noncompliance?
550.1455 Does my request for a hearing on the record affect the
penalties?
550.1456 May I request a hearing on the record regarding the amount of a
civil penalty if I did not request a hearing on the Notice of
Noncompliance?

Penalties Without a Period To Correct

550.1460 May I be subject to penalties without prior notice and an
opportunity to correct?
550.1461 How will BOEM inform me of violations without a period to
correct?
550.1462 How may I request a hearing on the record on a Notice of
Noncompliance regarding violations without a period to
correct?
550.1463 Does my request for a hearing on the record affect the
penalties?
550.1464 May I request a hearing on the record regarding the amount of a
civil penalty if I did not request a hearing on the Notice of
Noncompliance?

General Provisions

550.1470 How does BOEM decide what the amount of the penalty should be?
550.1471 Does the penalty affect whether I owe interest?
550.1472 How will the Office of Hearings and Appeals conduct the hearing
on the record?
550.1473 How may I appeal the Administrative Law Judge's decision?
550.1474 May I seek judicial review of the decision of the Interior
Board of Land Appeals?
550.1475 When must I pay the penalty?
550.1476 Can BOEM reduce my penalty once it is assessed?
550.1477 How may BOEM collect the penalty?

Criminal Penalties

550.1480 May the United States criminally prosecute me for violations
under Federal oil and gas leases?

Bonding Requirements

550.1490 What standards must my BOEM-specified surety instrument meet?
550.1491 How will BOEM determine the amount of my bond or other surety
instrument?

Financial Solvency Requirements

550.1495 How do I demonstrate financial solvency?
550.1496 How will BOEM determine if I am financially solvent?
550.1497 When will BOEM monitor my financial solvency?

Subparts O-S [Reserved]

Authority: 30 U.S.C. 1751; 31 U.S.C. 9701; 43 U.S.C. 1334.

Source: 76 FR 64623, Oct. 18, 2011, unless otherwise noted.

Subpart A_General

Authority and Definition of Terms

Sec. 550.101 Authority and applicability.

The Secretary of the Interior (Secretary) authorized the Bureau of
Ocean Energy Management (BOEM) to regulate oil, gas, and sulphur
exploration, development, and production operations on the Outer
Continental Shelf (OCS). Under the Secretary's authority, the Director
requires that all operations:
(a) Be conducted according to the OCS Lands Act (OCSLA), the
regulations in this part, BOEM orders, the lease or right-of-way, and
other applicable laws, regulations, and amendments; and
(b) Conform to sound conservation practice to preserve, protect, and
develop mineral resources of the OCS to:
(1) Make resources available to meet the Nation's energy needs;
(2) Balance orderly energy resource development with protection of
the human, marine, and coastal environments;
(3) Ensure the public receives a fair and equitable return on the
resources of the OCS;
(4) Preserve and maintain free enterprise competition; and

[[Page 354]]

(5) Minimize or eliminate conflicts between the exploration,
development, and production of oil and natural gas and the recovery of
other resources.

Sec. 550.102 What does this part do?

(a) 30 CFR part 550 contains the regulations of the BOEM Offshore
program that govern oil, gas, and sulphur exploration, development, and
production operations on the OCS. When you conduct operations on the
OCS, you must submit requests, applications, and notices, or provide
supplemental information for BOEM approval.
(b) The following table of general references shows where to look
for information about these processes.

Table--Where To Find Information for Conducting Operations
------------------------------------------------------------------------
For information about Refer to
------------------------------------------------------------------------
(1) Applications for permit to drill... 30 CFR 250, subpart D.
(2) Development and Production Plans 30 CFR 550, subpart B.
(DPP).
(3) Downhole commingling............... 30 CFR 250, subpart K.
(4) Exploration Plans (EP)............. 30 CFR 550, subpart B.
(5) Flaring............................ 30 CFR 250, subpart K.
(6) Gas measurement.................... 30 CFR 250, subpart L.
(7) Off-lease geological and 30 CFR 551.
geophysical permits.
(8) Oil spill financial responsibility 30 CFR 553.
coverage.
(9) Oil and gas production safety 30 CFR 250, subpart H.
systems.
(10) Oil spill response plans.......... 30 CFR 254.
(11) Oil and gas well-completion 30 CFR 250, subpart E.
operations.
(12) Oil and gas well-workover 30 CFR 250, subpart F.
operations.
(13) Decommissioning Activities........ 30 CFR 250, subpart Q.
(14) Platforms and structures.......... 30 CFR 250, subpart I.
(15) Pipelines and Pipeline Rights-of- 30 CFR 250, subpart J and 30
Way. CFR 550, subpart J.
(16) Sulphur operations................ 30 CFR 250, subpart P.
(17) Training.......................... 30 CFR 250, subpart O.
(18) Unitization....................... 30 CFR 250, subpart M.
------------------------------------------------------------------------

Sec. 550.103 Where can I find more information about the requirements
in this part?

BOEM may issue Notices to Lessees and Operators (NTLs) that clarify,
supplement, or provide more detail about certain requirements. NTLs may
also outline what you must provide as required information in your
various submissions to BOEM.

Sec. 550.104 How may I appeal a decision made under BOEM regulations?

To appeal orders or decisions issued under BOEM regulations in 30
CFR parts 550 to 582, follow the procedures in 30 CFR part 590.

Sec. 550.105 Definitions.

[[Page 355]]

(5) In which the Secretary finds that because of such activity there
is, or will be, a significant risk of serious damage, due to factors
such as prevailing winds and currents to the marine or coastal
environment in the event of any oil spill, blowout, or release of oil or
gas from vessels, pipelines, or other transshipment facilities.
Air pollutant means any airborne agent or combination of agents for
which the Environmental Protection Agency (EPA) has established, under
section 109 of the Clean Air Act, national primary or secondary ambient
air quality standards.
Analyzed geological information means data collected under a permit
or a lease that have been analyzed. Analysis may include, but is not
limited to, identification of lithologic and fossil content, core
analysis, laboratory analyses of physical and chemical properties, well
logs or charts, results from formation fluid tests, and descriptions of
hydrocarbon occurrences or hazardous conditions.
Ancillary activities mean those activities on your lease or unit
that you:
(1) Conduct to obtain data and information to ensure proper
exploration or development of your lease or unit; and
(2) Can conduct without BOEM approval of an application or permit.
Archaeological interest means capable of providing scientific or
humanistic understanding of past human behavior, cultural adaptation,
and related topics through the application of scientific or scholarly
techniques, such as controlled observation, contextual measurement,
controlled collection, analysis, interpretation, and explanation.
Archaeological resource means any material remains of human life or
activities that are at least 50 years of age and that are of
archaeological interest.
Arctic OCS means the Beaufort Sea and Chukchi Sea Planning Areas
(for more information on these areas, see the Proposed Final OCS Oil and
Gas Leasing Program for 2012-2017 (June 2012) at http://www.boem.gov/
Oil-and-Gas-Energy-Program/Leasing/Five-Year-Program/ 2012-2017/Program-
Area-Maps/index.aspx).
Arctic OCS conditions means, for the purposes of this part, the
conditions operators can reasonably expect during operations on the
Arctic OCS. Such conditions, depending on the time of year, include, but
are not limited to: extreme cold, freezing spray, snow, extended periods
of low light, strong winds, dense fog, sea ice, strong currents, and
dangerous sea states. Remote location, relative lack of infrastructure,
and the existence of subsistence hunting and fishing areas are also
characteristic of the Arctic region.
Attainment area means, for any air pollutant, an area that is shown
by monitored data or that is calculated by air quality modeling (or
other methods determined by the Administrator of EPA to be reliable) not
to exceed any primary or secondary ambient air quality standards
established by EPA.
Best available and safest technology (BAST) means the best available
and safest technologies that the Director determines to be economically
feasible wherever failure of equipment would have a significant effect
on safety, health, or the environment.
Best available control technology (BACT) means an emission
limitation based on the maximum degree of reduction for each air
pollutant subject to regulation, taking into account energy,
environmental and economic impacts, and other costs. The Regional
Director will verify the BACT on a case-by-case basis, and it may
include reductions achieved through the application of processes,
systems, and techniques for the control of each air pollutant.
Coastal environment means the physical, atmospheric, and biological
components, conditions, and factors that interactively determine the
productivity, state, condition, and quality of the terrestrial ecosystem
from the shoreline inward to the boundaries of the coastal zone.
Coastal zone means the coastal waters (including the lands therein
and thereunder) and the adjacent shorelands (including the waters
therein and thereunder) strongly influenced by each other and in
proximity to the shorelands of the several coastal States. The coastal
zone includes islands, transition and intertidal areas, salt marshes,
wetlands, and beaches. The coastal zone extends seaward to the outer
limit of the U.S. territorial

[[Page 356]]

sea and extends inland from the shorelines to the extent necessary to
control shorelands, the uses of which have a direct and significant
impact on the coastal waters, and the inward boundaries of which may be
identified by the several coastal States, under the authority in section
305(b)(1) of the Coastal Zone Management Act (CZMA) of 1972.
Competitive reservoir means a reservoir in which there are one or
more producible or producing well completions on each of two or more
leases or portions of leases, with different lease operating interests,
from which the lessees plan future production.
Correlative rights when used with respect to lessees of adjacent
leases, means the right of each lessee to be afforded an equal
opportunity to explore for, develop, and produce, without waste,
minerals from a common source.
Data means facts and statistics, measurements, or samples that have
not been analyzed, processed, or interpreted.
Departures mean approvals granted by the appropriate BSEE or BOEM
representative for operating requirements/procedures other than those
specified in the regulations found in this part. These requirements/
procedures may be necessary to control a well; properly develop a lease;
conserve natural resources, or protect life, property, or the marine,
coastal, or human environment.
Development means those activities that take place following
discovery of minerals in paying quantities, including but not limited to
geophysical activity, drilling, platform construction, and operation of
all directly related onshore support facilities, and which are for the
purpose of producing the minerals discovered.
Development geological and geophysical (G&G) activities means those
G&G and related data-gathering activities on your lease or unit that you
conduct following discovery of oil, gas, or sulphur in paying quantities
to detect or imply the presence of oil, gas, or sulphur in commercial
quantities.
Director means the Director of BOEM of the U.S. Department of the
Interior, or an official authorized to act on the Director's behalf.
District Manager means the BSEE officer with authority and
responsibility for operations or other designated program functions for
a district within a BSEE Region.
Easement means an authorization for a nonpossessory, nonexclusive
interest in a portion of the OCS, whether leased or unleased, which
specifies the rights of the holder to use the area embraced in the
easement in a manner consistent with the terms and conditions of the
granting authority.
Eastern Gulf of Mexico means all OCS areas of the Gulf of Mexico the
BOEM Director decides are adjacent to the State of Florida. The Eastern
Gulf of Mexico is not the same as the Eastern Planning Area, an area
established for OCS lease sales.
Emission offsets mean emission reductions obtained from facilities,
either onshore or offshore, other than the facility or facilities
covered by the proposed Exploration Plan (EP) or Development and
Production Plan (DPP).
Enhanced recovery operations mean pressure maintenance operations,
secondary and tertiary recovery, cycling, and similar recovery
operations that alter the natural forces in a reservoir to increase the
ultimate recovery of oil or gas.
Existing facility, as used in Sec. 550.303, means an OCS facility
described in an Exploration Plan or a Development and Production Plan
approved before June 2, 1980.
Exploration means the commercial search for oil, gas, or sulphur.
Activities classified as exploration include but are not limited to:
(1) Geophysical and geological (G&G) surveys using magnetic,
gravity, seismic reflection, seismic refraction, gas sniffers, coring,
or other systems to detect or imply the presence of oil, gas, or
sulphur; and
(2) Any drilling conducted for the purpose of searching for
commercial quantities of oil, gas, and sulphur, including the drilling
of any additional well needed to delineate any reservoir to enable the
lessee to decide whether to proceed with development and production.
Facility, as used in Sec. 550.303, means all installations or
devices permanently or temporarily attached to the seabed.

[[Page 357]]

They include mobile offshore drilling units (MODUs), even while
operating in the ``tender assist'' mode (i.e., with skid-off drilling
units) or other vessels engaged in drilling or downhole operations. They
are used for exploration, development, and production activities for
oil, gas, or sulphur and emit or have the potential to emit any air
pollutant from one or more sources. They include all floating production
systems (FPSs), including column-stabilized-units (CSUs); floating
production, storage and offloading facilities (FPSOs); tension-leg
platforms (TLPs); spars, etc. During production, multiple installations
or devices are a single facility if the installations or devices are at
a single site. Any vessel used to transfer production from an offshore
facility is part of the facility while it is physically attached to the
facility.
Flaring means the burning of natural gas as it is released into the
atmosphere.
Gas reservoir means a reservoir that contains hydrocarbons
predominantly in a gaseous (single-phase) state.
Gas-well completion means a well completed in a gas reservoir or in
the associated gas-cap of an oil reservoir.
Geological and geophysical (G&G) explorations means those G&G
surveys on your lease or unit that use seismic reflection, seismic
refraction, magnetic, gravity, gas sniffers, coring, or other systems to
detect or imply the presence of oil, gas, or sulphur in commercial
quantities.
Governor means the Governor of a State, or the person or entity
designated by, or under, State law to exercise the powers granted to
such Governor under the Act.
H2S absent means:
(1) Drilling, logging, coring, testing, or producing operations have
confirmed the absence of H2S in concentrations that could
potentially result in atmospheric concentrations of 20 ppm or more of
H2S; or
(2) Drilling in the surrounding areas and correlation of geological
and seismic data with equivalent stratigraphic units have confirmed an
absence of H2S throughout the area to be drilled.
H2S present means drilling, logging, coring, testing, or producing
operations have confirmed the presence of H2S in
concentrations and volumes that could potentially result in atmospheric
concentrations of 20 ppm or more of H2S.
H2S unknown means the designation of a zone or geologic formation
where neither the presence nor absence of H2S has been
confirmed.
Human environment means the physical, social, and economic
components, conditions, and factors that interactively determine the
state, condition, and quality of living conditions, employment, and
health of those affected, directly or indirectly, by activities
occurring on the OCS.
Interpreted geological information means geological knowledge, often
in the form of schematic cross sections, 3-dimensional representations,
and maps, developed by determining the geological significance of data
and analyzed geological information.
Interpreted geophysical information means geophysical knowledge,
often in the form of schematic cross sections, 3-dimensional
representations, and maps, developed by determining the geological
significance of geophysical data and analyzed geophysical information.
Lease means an agreement that is issued under section 8 or
maintained under section 6 of the Act and that authorizes exploration
for, and development and production of, minerals. The term also means
the area covered by that authorization, whichever the context requires.
Lease term pipelines mean those pipelines owned and operated by a
lessee or operator that are completely contained within the boundaries
of a single lease, unit, or contiguous (not cornering) leases of that
lessee or operator.
Lessee means a person who has entered into a lease with the United
States to explore for, develop, and produce the leased minerals. The
term lessee also includes the BOEM-approved assignee of the lease, and
the owner or the BOEM-approved assignee of operating rights for the
lease.
Major Federal action means any action or proposal by the Secretary
that is subject to the provisions of section 102(2)(C) of the National
Environmental Policy Act of 1969, 42 U.S.C. (2)(C) (i.e., an action that
will have a significant

[[Page 358]]

impact on the quality of the human environment requiring preparation of
an environmental impact statement under section 102(2)(C) of the
National Environmental Policy Act).
Marine environment means the physical, atmospheric, and biological
components, conditions, and factors that interactively determine the
productivity, state, condition, and quality of the marine ecosystem.
These include the waters of the high seas, the contiguous zone,
transitional and intertidal areas, salt marshes, and wetlands within the
coastal zone and on the OCS.
Material remains means physical evidence of human habitation,
occupation, use, or activity, including the site, location, or context
in which such evidence is situated.
Maximum efficient rate (MER) means the maximum sustainable daily oil
or gas withdrawal rate from a reservoir that will permit economic
development and depletion of that reservoir without detriment to
ultimate recovery.
Maximum production rate (MPR) means the approved maximum daily rate
at which oil or gas may be produced from a specified oil-well or gas-
well completion.
Minerals include oil, gas, sulphur, geopressured-geothermal and
associated resources, and all other minerals that are authorized by an
Act of Congress to be produced.
Natural resources include, without limiting the generality thereof,
oil, gas, and all other minerals, and fish, shrimp, oysters, clams,
crabs, lobsters, sponges, kelp, and other marine animal and plant life
but does not include water power or the use of water for the production
of power.
Nonattainment area means, for any air pollutant, an area that is
shown by monitored data or that is calculated by air quality modeling
(or other methods determined by the Administrator of EPA to be reliable)
to exceed any primary or secondary ambient air quality standard
established by EPA.
Nonsensitive reservoir means a reservoir in which ultimate recovery
is not decreased by high reservoir production rates.
Oil reservoir means a reservoir that contains hydrocarbons
predominantly in a liquid (single-phase) state.
Oil reservoir with an associated gas cap means a reservoir that
contains hydrocarbons in both a liquid and gaseous (two-phase) state.
Oil-well completion means a well completed in an oil reservoir or in
the oil accumulation of an oil reservoir with an associated gas cap.
Operating rights mean any interest held in a lease with the right to
explore for, develop, and produce leased substances.
Operator means the person the lessee(s) designates as having control
or management of operations on the leased area or a portion thereof. An
operator may be a lessee, the BOEM-approved or BSEE-approved designated
agent of the lessee(s), or the holder of operating rights under a BOEM-
approved operating rights assignment.
Outer Continental Shelf (OCS) means all submerged lands lying
seaward and outside of the area of lands beneath navigable waters as
defined in section 2 of the Submerged Lands Act (43 U.S.C. 1301) whose
subsoil and seabed appertain to the United States and are subject to its
jurisdiction and control.
Person includes a natural person, an association (including
partnerships, joint ventures, and trusts), a State, a political
subdivision of a State, or a private, public, or municipal corporation.
Pipelines are the piping, risers, and appurtenances installed for
transporting oil, gas, sulphur, and produced waters.
Processed geological or geophysical information means data collected
under a permit or a lease that have been processed or reprocessed.
Processing involves changing the form of data to facilitate
interpretation. Processing operations may include, but are not limited
to, applying corrections for known perturbing causes, rearranging or
filtering data, and combining or transforming data elements.
Reprocessing is the additional processing other than ordinary processing
used in the general course of evaluation. Reprocessing operations may
include varying identified parameters for the detailed study of a
specific problem area.
Production means those activities that take place after the
successful

[[Page 359]]

completion of any means for the removal of minerals, including such
removal, field operations, transfer of minerals to shore, operation
monitoring, maintenance, and workover operations.
Production areas are those areas where flammable petroleum gas,
volatile liquids or sulphur are produced, processed (e.g., compressed),
stored, transferred (e.g., pumped), or otherwise handled before entering
the transportation process.
Projected emissions mean emissions, either controlled or
uncontrolled, from a source or sources.
Prospect means a geologic feature having the potential for mineral
deposits.
Regional Director means the BOEM officer with responsibility and
authority for a Region within BOEM.
Regional Supervisor means the BOEM officer with responsibility and
authority for operations or other designated program functions within a
BOEM Region.
Right-of-use means any authorization issued under this part to use
OCS lands.
Right-of-way pipelines are those pipelines that are contained
within:
(1) The boundaries of a single lease or unit, but are not owned and
operated by a lessee or operator of that lease or unit;
(2) The boundaries of contiguous (not cornering) leases that do not
have a common lessee or operator;
(3) The boundaries of contiguous (not cornering) leases that have a
common lessee or operator but are not owned and operated by that common
lessee or operator; or
(4) An unleased block(s).
Sensitive reservoir means a reservoir in which the production rate
will affect ultimate recovery.
Significant archaeological resource means those archaeological
resources that meet the criteria of significance for eligibility to the
National Register of Historic Places as defined in 36 CFR 60.4, or its
successor.
Suspension means a granted or directed deferral of the requirement
to produce (Suspension of Production (SOP)) or to conduct leaseholding
operations (Suspension of Operations (SOO)).
Venting means the release of gas into the atmosphere without
igniting it. This includes gas that is released underwater and bubbles
to the atmosphere.
Waste of oil, gas, or sulphur means:
(1) The physical waste of oil, gas, or sulphur;
(2) The inefficient, excessive, or improper use, or the unnecessary
dissipation of reservoir energy;
(3) The locating, spacing, drilling, equipping, operating, or
producing of any oil, gas, or sulphur well(s) in a manner that causes or
tends to cause a reduction in the quantity of oil, gas, or sulphur
ultimately recoverable under prudent and proper operations or that
causes or tends to cause unnecessary or excessive surface loss or
destruction of oil or gas; or
(4) The inefficient storage of oil.
Welding means all activities connected with welding, including hot
tapping and burning.
Wellbay is the area on a facility within the perimeter of the
outermost wellheads.
Well-completion operations mean the work conducted to establish
production from a well after the production-casing string has been set,
cemented, and pressure-tested.
Well-control fluid means drilling mud, completion fluid, or workover
fluid as appropriate to the particular operation being conducted.
Western Gulf of Mexico means all OCS areas of the Gulf of Mexico
except those the BOEM Director decides are adjacent to the State of
Florida. The Western Gulf of Mexico is not the same as the Western
Planning Area, an area established for OCS lease sales.
Workover operations mean the work conducted on wells after the
initial well-completion operation for the purpose of maintaining or
restoring the productivity of a well.
You means a lessee, the owner or holder of operating rights, a
designated operator or agent of the lessee(s), a pipeline right-of-way
holder, or a State lessee granted a right-of-use and easement.

[76 FR 64623, Oct. 18, 2011, as amended at 81 FR 46565, July 15, 2016]

[[Page 360]]

Performance Standards

Sec. 550.115 How do I determine well producibility?

You must follow the procedures in this section to determine well
producibility if your well is not in the GOM. If your well is in the GOM
you must follow the procedures in either this section or in Sec.
550.116 of this subpart.
(a) You must write to the Regional Supervisor asking for permission
to determine producibility.
(b) You must either:
(1) Allow the Regional Supervisor to witness each test that you
conduct under this section; or
(2) Receive the Regional Supervisor prior approval so that you can
submit either test data with your affidavit or third party test data.
(c) If the well is an oil well, you must conduct a production test
that lasts at least 2 hours after flow stabilizes.
(d) If the well is a gas well, you must conduct a deliverability
test that lasts at least 2 hours after flow stabilizes, or a four-point
back pressure test.

Sec. 550.116 How do I determine producibility if my well is
in the Gulf of Mexico?

If your well is in the GOM, you must follow either the procedures in
Sec. 550.115 of this subpart or the procedures in this section to
determine producibility.
(a) You must write to the Regional Supervisor asking for permission
to determine producibility.
(b) You must provide or make available to the Regional Supervisor,
as requested, the following log, core, analyses, and test criteria that
BOEM will consider collectively:
(1) A log showing sufficient porosity in the producible section.
(2) Sidewall cores and core analyses that show that the section is
capable of producing oil or gas.
(3) Wireline formation test and/or mud-logging analyses that show
that the section is capable of producing oil or gas.
(4) A resistivity or induction electric log of the well showing a
minimum of 15 feet (true vertical thickness except for horizontal wells)
of producible sand in one section.
(c) No section that you count as producible under paragraph (b)(4)
of this section may include any interval that appears to be water
saturated.
(d) Each section you count as producible under paragraph (b)(4) of
this section must exhibit:
(1) A minimum true resistivity ratio of the producible section to
the nearest clean or water-bearing sand of at least 5:1; and
(2) One of the following:
(i) Electrical spontaneous potential exceeding 20-negative
millivolts beyond the shale baseline; or
(ii) Gamma ray log deflection of at least 70 percent of the maximum
gamma ray deflection in the nearest clean water-bearing sand--if mud
conditions prevent a 20-negative millivolt reading beyond the shale
baseline.

Sec. 550.117 How does a determination of well producibility
affect royalty status?

A determination of well producibility invokes minimum royalty status
on the lease as provided in 30 CFR 1202.53.

Sec. 550.118 [Reserved]

Sec. 550.119 Will BOEM approve subsurface gas storage?

The Regional Supervisor may authorize subsurface storage of gas on
the OCS, on and off-lease, for later commercial benefit. The Regional
Supervisor may authorize subsurface storage of gas on the OCS, off-
lease, for later commercial benefit. To receive approval you must:
(a) Show that the subsurface storage of gas will not result in undue
interference with operations under existing leases; and
(b) Sign a storage agreement that includes the required payment of a
storage fee or rental.

Sec. 550.120 What standards will BOEM use to regulate leases, rights-of-use
and easement, and rights-of-way?

BOEM will regulate all activities under a lease, a right-of-use and
easement, or a right-of-way to:
(a) Promote the orderly exploration, development, and production of
mineral resources;
(b) Prevent injury or loss of life;

[[Page 361]]

(c) Prevent damage to or waste of any natural resource, property, or
the environment; and
(d) Ensure cooperation and consultation with affected States, local
governments, other interested parties, and relevant Federal agencies.

[81 FR 18152, Mar. 30, 2016]

Sec. 550.121 What must I do to protect health, safety, property,
and the environment?

The Director may require additional measures to ensure the use of
Best Available and Safest Technology (BAST) as identified by BSEE:
(a) To avoid the failure of equipment that would have a significant
effect on safety, health, or the environment;
(b) If it is economically feasible; and
(c) If the incremental benefits justify the incremental costs.

[81 FR 18152, Mar. 30, 2016]

Sec. 550.122 What effect does subsurface storage have on the lease term?

If you use a lease area for subsurface storage of gas, it does not
affect the continuance or expiration of the lease.

Sec. 550.123 Will BOEM allow gas storage on unleased lands?

You may not store gas on unleased lands unless the Regional
Supervisor approves a right-of-use and easement for that purpose, under
Sec. Sec. 550.160 through 550.166 of this subpart.

Fees

Sec. 550.125 Service fees.

(a) The table in this paragraph (a) shows the fees that you must pay
to BOEM for the services listed. The fees will be adjusted periodically
according to the Implicit Price Deflator for Gross Domestic Product by
publication of a document in the Federal Register. If a significant
adjustment is needed to arrive at the new actual cost for any reason
other than inflation, then a proposed rule containing the new fees will
be published in the Federal Register for comment.

------------------------------------------------------------------------
Service--processing of the
following: Fee amount 30 CFR citation
------------------------------------------------------------------------
(1) Change in Designation of $164................. Sec. 550.143(d).
Operator.
(2) Right-of-Use and Easement $2,569............... Sec. 550.165.
for State lessee.
(3) [Reserved]...............
(4) Exploration Plan (EP).... $3,442 for each Sec. 550.211(d).
surface location; no
fee for revisions.
(5) Development and $3,971 for each well Sec. 550.241(e).
Production Plan (DPP) or proposed; no fee for
Development Operations revisions.
Coordination Document (DOCD).
(6) [Reserved]...............
(7) Conservation Information $25,629.............. Sec. 550.296(a).
Document.
------------------------------------------------------------------------

Sec. 550.126 Electronic payment instructions.

You must file all payments electronically through Pay.gov. This
includes, but is not limited to, all OCS applications or filing fee
payments. The Pay.gov Web site may be accessed through Pay.gov at
https://www.pay.gov/paygov/.
(a) [Reserved]
(b) You must use credit card or automated clearing house (ACH)
payments

[[Page 362]]

through the Pay.gov Web site, and you must include a copy of the Pay.gov
confirmation receipt page with your application.

[76 FR 64623, Oct. 18, 2011, as amended at 80 FR 57096, Sept. 22, 2015]

Inspection of Operations

Sec. 550.130 [Reserved]

Disqualification

Sec. 550.135 What will BOEM do if my operating performance is unacceptable?

If your operating performance is unacceptable, BOEM may disapprove
or revoke your designation as operator on a single facility or multiple
facilities. We will give you adequate notice and opportunity for a
review by BOEM officials before imposing a disqualification.

Sec. 550.136 How will BOEM determine if my performance is unacceptable?

In determining if your operating performance is unacceptable, BOEM
will consider, individually or collectively:
(a)-(b) [Reserved]
(c) Incidents of noncompliance;
(d) Civil penalties;
(e) Failure to adhere to OCS lease obligations; or
(f) Any other relevant factors.

Special Types of Approvals

Sec. 550.140 When will I receive an oral approval?

When you apply for BOEM approval of any activity, we normally give
you a written decision. The following table shows circumstances under
which we may give an oral approval.

Sec. 550.141 May I ever use alternate procedures or equipment?

You may use alternate procedures or equipment after receiving
approval as described in this section.
(a) Any alternate procedures or equipment that you propose to use
must provide a level of safety and environmental protection that equals
or surpasses current BOEM requirements.
(b) You must receive the Regional Supervisor's written approval
before you can use alternate procedures or equipment.
(c) To receive approval, you must either submit information or give
an oral presentation to the appropriate Regional Supervisor. Your
presentation must describe the site-specific application(s), performance
characteristics, and safety features of the proposed procedure or
equipment.

Sec. 550.142 How do I receive approval for departures?

We may approve departures to the operating requirements. You may
apply for a departure by writing to the Regional Supervisor.

Sec. 550.143 How do I designate an operator?

(a) You must provide the Regional Supervisor an executed Designation
of Operator form (Form BOEM-1123) unless you are the only lessee and are
the only person conducting lease operations. When there is more than one
lessee, each lessee must submit the Designation of Operator form and the
Regional Supervisor must approve the designation before the designated
operator may begin operations on the leasehold.
(b) This designation is authority for the designated operator to act
on your behalf and to fulfill your obligations under the Act, the lease,
and the regulations in this part.
(c) You, or your designated operator, must immediately provide the
Regional Supervisor a written notification of any change of address.
(d) If you change the designated operator on your lease, you must
pay the

[[Page 363]]

service fee listed in Sec. 550.125 of this subpart with your request
for a change in designation of operator. Should there be multiple
lessees, all designation of operator forms must be collected by one
lessee and submitted to BOEM in a single submittal, which is subject to
only one filing fee.

Sec. 550.144 How do I designate a new operator when a designation
of operator terminates?

(a) When a Designation of Operator terminates, the Regional
Supervisor must approve a new designated operator before you may
continue operations. Each lessee must submit a new executed Designation
of Operator form.
(b) If your Designation of Operator is terminated, or a controversy
develops between you and your designated operator, you and your
designated operator must protect the lessor's interests.

Sec. 550.146 How do I designate an agent or a local agent?

(a) You or your designated operator may designate for the Regional
Supervisor's approval, or the Regional Director may require you to
designate an agent empowered to fulfill your obligations under the Act,
the lease, or the regulations in this part.
(b) You or your designated operator may designate for the Regional
Supervisor's approval a local agent empowered to receive notices and
submit requests, applications, notices, or supplemental information.

[76 FR 64623, Oct. 18, 2011. Redesignated at 81 FR 18152, Mar. 30, 2016]

Sec. 550.147 Who is responsible for fulfilling leasehold obligations?

[76 FR 64623, Oct. 18, 2011. Redesignated at 81 FR 18152, Mar. 30, 2016]

Right-of-Use and Easement

Sec. 550.160 When will BOEM grant me a right-of-use and easement,
and what requirements must I meet?

BOEM may grant you a right-of-use and easement on leased and
unleased lands on the OCS, if you meet these requirements:
(a) You must need the right-of-use and easement to construct and
maintain platforms, artificial islands, and installations and other
devices at an OCS site other than an OCS lease you own, that are:
(1) Permanently or temporarily attached to the seabed; and
(2) Used for conducting exploration, development, and production
activities or other operations on or off lease; or
(3) Used for other purposes approved by BOEM.
(b) You must exercise the right-of-use and easement according to the
regulations of this part;
(c) You must meet the requirements at 30 CFR 556.35 (Qualification
of lessees); establish a regional Company File as required by BOEM; and
must meet bonding requirements;
(d) If you apply for a right-of-use and easement on a leased area,
you must notify the lessee and give her/him an opportunity to comment on
your application; and
(e) You must receive BOEM approval for all platforms, artificial
islands, and installations and other devices permanently or temporarily
attached to the seabed.
(f) You must pay a rental amount as required by paragraph (g) of
this section if:

[[Page 364]]

(1) You obtain a right-of-use and easement after January 12, 2004;
or
(2) You ask BOEM to modify your right-of-use and easement to change
the footprint of the associated platform, artificial island, or
installation or device.
(g) If you meet either of the conditions in paragraph (f) of this
section, you must pay a rental amount to BOEM as shown in the following
table:

------------------------------------------------------------------------
If . . . Then . . .
------------------------------------------------------------------------
(1) Your right-of-use and easement You must pay a rental of $5 per acre
site is located in water depths per year with a minimum of $450 per
of less than 200 meters; year. The area subject to annual
rental includes the areal extent of
anchor chains, pipeline risers, and
other equipment associated with the
platform, artificial island,
installation or device.
(2) Your right-of-use and easement You must pay a rental of $7.50 per
site is located in water depths acre per year with a minimum of
of 200 meters or greater; $675 per year. The area subject to
annual rental includes the areal
extent of anchor chains, pipeline
risers, and other equipment
associated with the platform,
artificial island, or installation
or device.
------------------------------------------------------------------------

(h) You may make the rental payments required by paragraph (g)(1)
and (g)(2) of this section on an annual basis, for a 5-year period, or
for multiples of 5 years. You must make the first payment electronically
through Pay.gov and you must include a copy of the Pay.gov confirmation
receipt page with your right-of-use and easement application. You must
make all subsequent payments before the respective time periods begin.
(i) Late payments. An interest charge will be assessed on unpaid and
underpaid amounts from the date the amounts are due, in accordance with
the provisions found in 30 CFR 1218.54. If you fail to make a payment
that is late after written notice from BOEM, BOEM may initiate
cancellation of the right-of-use grant and easement.

Sec. 550.161 What else must I submit with my application?

With your application, you must describe the proposed use giving:
(a) Details of the proposed uses and activities including access
needs and special rights of use that you may need;
(b) A description of all facilities for which you are seeking
authorization;
(c) A map or plat describing primary and alternate project
locations; and
(d) A schedule for constructing any new facilities, drilling or
completing any wells, anticipated production rates, and productive life
of existing production facilities.

Sec. 550.162 May I continue my right-of-use and easement after
the termination of any lease on which it is situated?

If your right-of-use and easement is on a lease, you may continue to
exercise the right-of-use and easement after the lease on which it is
situated terminates. You must only use the right-of-use and easement for
the purpose that the grant specifies. All future lessees of that portion
of the OCS on which your right-of-use and easement is situated must
continue to recognize the right-of-use and easement for the purpose that
the grant specifies.

Sec. 550.163 If I have a State lease, will BOEM grant me a right-of-use
and easement?

(a) BOEM may grant a lessee of a State lease located adjacent to or
accessible from the OCS a right-of-use and easement on the OCS.
(b) BOEM will only grant a right-of-use and easement under this
paragraph to enable a State lessee to conduct and maintain a device that
is permanently or temporarily attached to the seabed (i.e., a platform,
artificial island, or installation). The lessee must use the device to
explore for, develop, and produce oil and gas from the adjacent or
accessible State lease and for other operations related to these
activities.

Sec. 550.164 If I have a State lease, what conditions apply for
a right-of-use and easement?

(a) A right-of-use and easement granted under the heading of
``Right-of-use and easement'' in this subpart is

[[Page 365]]

subject to BOEM regulations, 30 CFR parts 550 through 582, BSEE
regulations, 30 CFR parts 250 through 282, and any terms and conditions
that the BOEM Regional Director or BSEE Regional Director prescribes.
(b) For the whole or fraction of the first calendar year, and
annually after that, you must pay to BOEM, in advance, an annual rental
payment.

Sec. 550.165 If I have a State lease, what fees do I have to pay
for a right-of-use and easement?

When you apply for a right-of-use and easement, you must pay:
(a) A nonrefundable filing fee as specified in Sec. 550.125; and
(b) The first year's rental as specified in Sec. 550.160(g).

Sec. 550.166 If I have a State lease, what surety bond must I have
for a right-of-use and easement?

(a) Before BOEM issues you a right-of-use and easement on the OCS,
you must furnish the Regional Director a surety bond for $500,000.
(b) The Regional Director may require additional security from you
(i.e., security above the prescribed $500,000) to cover additional costs
and liabilities for regulatory compliance. This additional surety:
(1) Must be in the form of a supplemental bond or bonds meeting the
requirements of 30 CFR 556.54 (General requirements for bonds) or an
increase in the coverage of an existing surety bond.
(2) Covers additional costs and liabilities for regulatory
compliance, including well abandonment, platform and structure removal,
and site clearance from the seafloor of the right-of-use and easement.

Primary Lease Requirements, Lease Term Extensions, and Lease
Cancellations

Sec. 550.181 When may the Secretary cancel my lease and when am I
compensated for cancellation?

If the Secretary cancels your lease under this part or under 30 CFR
part 556, you are entitled to compensation under Sec. 550.184. Section
550.185 states conditions under which you will receive no compensation.
The Secretary may cancel a lease after notice and opportunity for a
hearing when:
(a) Continued activity on the lease would probably cause harm or
damage to life (including fish and other aquatic life), property, any
mineral deposits (in areas leased or not leased), or the marine,
coastal, or human environment;
(b) The threat of harm or damage will not disappear or decrease to
an acceptable extent within a reasonable period of time;
(c) The advantages of cancellation outweigh the advantages of
continuing the lease in force; and
(d) A suspension has been in effect for at least 5 years or you
request termination of the suspension and lease cancellation.

Sec. 550.182 When may the Secretary cancel a lease at the exploration stage?

BOEM may not approve an exploration plan (EP) under 30 CFR part 550,
subpart B, if the Regional Supervisor determines that the proposed
activities may cause serious harm or damage to life (including fish and
other aquatic life), property, any mineral deposits, the National
security or defense, or to the marine, coastal, or human environment,
and that the proposed activity cannot be modified to avoid the
condition(s). The Secretary may cancel the lease if:
(a) The primary lease term has not expired (or if the lease term has
been extended) and exploration has been prohibited for 5 years following
the disapproval; or
(b) You request cancellation at an earlier time.

Sec. 550.183 When may BOEM or the Secretary extend or cancel a lease
at the development and production stage?

(a) BOEM may extend your lease if you submit a DPP and the Regional
Supervisor disapproves the plan according to the regulations in 30 CFR
part 550, subpart B. Following the disapproval:
(1) BOEM will allow you to hold the lease for 5 years, or less time
at your request;

[[Page 366]]

(2) Any time within 5 years after the disapproval, you may reapply
for approval of the same or a modified plan; and
(3) The Regional Supervisor will approve, disapprove, or require
modification of the plan under 30 CFR part 550, subpart B.
(b) If the Regional Supervisor has not approved a DPP or required
you to submit a DPP for approval or modification, the Secretary will
cancel the lease:
(1) When the 5-year period in paragraph (a)(1) of this section
expires; or
(2) If you request cancellation at an earlier time.

Sec. 550.184 What is the amount of compensation for lease cancellation?

When the Secretary cancels a lease under Sec. Sec. 550.181, 550.182
or 550.183 of this subpart, you are entitled to receive compensation
under 43 U.S.C. 1334(a)(2)(C). You must show the Director that the
amount of compensation claimed is the lesser of paragraph (a) or (b) of
this section:
(a) The fair value of the cancelled rights as of the date of
cancellation, taking into account both:
(1) Anticipated revenues from the lease; and
(2) Costs reasonably anticipated on the lease, including:
(i) Costs of compliance with all applicable regulations and
operating orders; and
(ii) Liability for cleanup costs or damages, or both, in the case of
an oil spill.
(b) The excess, if any, over your revenues from the lease (plus
interest thereon from the date of receipt to date of reimbursement) of:
(1) All consideration paid for the lease (plus interest from the
date of payment to the date of reimbursement); and
(2) All your direct expenditures (plus interest from the date of
payment to the date of reimbursement):
(i) After the issue date of the lease; and
(ii) For exploration or development, or both.
(c) Compensation for leases issued before September 18, 1978, will
be equal to the amount specified in paragraph (a) of this section.

Sec. 550.185 When is there no compensation for a lease cancellation?

You will not receive compensation from BOEM for lease cancellation
if:
(a) BOEM disapproves a DPP because you do not receive concurrence by
the State under section 307(c)(3)(B)(i) or (ii) of the CZMA, and the
Secretary of Commerce does not make the finding authorized by section
307(c)(3)(B)(iii) of the CZMA;
(b) You do not submit a DPP under 30 CFR part 550, subpart B or do
not comply with the approved DPP;
(c) As the lessee of a nonproducing lease, you fail to comply with
the Act, the lease, or the regulations issued under the Act, and the
default continues for 30 days after BOEM mails you a notice by overnight
mail;
(d) The Regional Supervisor disapproves a DPP because you fail to
comply with the requirements of applicable Federal law; or
(e) The Secretary forfeits and cancels a producing lease under
section 5(d) of the Act (43 U.S.C. 1334(d)).

Information and Reporting Requirements

Sec. 550.186 What reporting information and report forms must I submit?

(a) You must submit information and reports as BOEM requires.
(1) You may obtain copies of forms from, and submit completed forms
to, the Regional Supervisor.
(2) Instead of paper copies of forms available from the Regional
Supervisor, you may use your own computer-generated forms that are equal
in size to BOEM's forms. You must arrange the data on your form
identical to the BOEM form. If you generate your own form and it omits
terms and conditions contained on the official BOEM form, we will
consider it to contain the omitted terms and conditions.
(3) You may submit digital data when the Region is equipped to
accept it.
(b) When BOEM specifies, you must include, for public information,
an additional copy of such reports.
(1) You must mark it Public Information.

[[Page 367]]

(2) You must include all required information, except information
exempt from public disclosure under Sec. 550.197 or otherwise exempt
from public disclosure under law or regulation.

Sec. Sec. 550.187-550.193 [Reserved]

Sec. 550.194 How must I protect archaeological resources?

(a) If the Regional Director has reason to believe that an
archaeological resource may exist in the lease area, the Regional
Director will require in writing that your EP, DOCD, or DPP be
accompanied by an archaeological report. If the archaeological report
suggests that an archaeological resource may be present, you must
either:
(1) Locate the site of any operation so as not to adversely affect
the area where the archaeological resource may be; or
(2) Establish to the satisfaction of the Regional Director that an
archaeological resource does not exist or will not be adversely affected
by operations. This requires further archaeological investigation,
conducted by an archaeologist and a geophysicist, using survey equipment
and techniques the Regional Director considers appropriate. You must
submit the investigation report to the Regional Director for review.
(b) If the Regional Director determines that an archaeological
resource is likely to be present in the lease area and may be adversely
affected by operations, the Regional Director will notify you
immediately. You must not take any action that may adversely affect the
archaeological resource until the Regional Director has told you how to
protect the resource.
(c) If you discover any archaeological resource while conducting
operations in the lease or right-of-way area, you must immediately halt
operations within the area of the discovery and report the discovery to
the BOEM Regional Director. If investigations determine that the
resource is significant, the Regional Director will tell you how to
protect it.

Sec. 550.195 [Reserved]

Sec. 550.196 Reimbursements for reproduction and processing costs.

(a) BOEM will reimburse you for costs of reproducing data and
information that the Regional Director requests if:
(1) You deliver geophysical and geological (G&G) data and
information to BOEM for the Regional Director to inspect or select and
retain;
(2) BOEM receives your request for reimbursement and the Regional
Director determines that the requested reimbursement is proper; and
(3) The cost is at your lowest rate or at the lowest commercial rate
established in the area, whichever is less.
(b) BOEM will reimburse you for the costs of processing geophysical
information (that does not include cost of data acquisition):
(1) If, at the request of the Regional Director, you processed the
geophysical data or information in a form or manner other than that used
in the normal conduct of business; or
(2) If you collected the information under a permit that BOEM issued
to you before October 1, 1985, and the Regional Director requests and
retains the information.
(c) When you request reimbursement, you must identify reproduction
and processing costs separately from acquisition costs.
(d) BOEM will not reimburse you for data acquisition costs or for
the costs of analyzing or processing geological information or
interpreting geological or geophysical information.

Sec. 550.197 Data and information to be made available to the public
or for limited inspection.

BOEM will protect data and information that you submit under this
chapter, as described in this section. Paragraphs (a) and (b) of this
section describe what data and information will be made available to the
public without the consent of the lessee, under what circumstances, and
in what time period. Paragraph (c) of this section describes what data
and information will be made available for limited inspection without
the consent of the lessee, and under what circumstances.

[[Page 368]]

(a) All data and information you submit on BOEM forms will be made
available to the public upon submission, except as specified in the
following table:

------------------------------------------------------------------------
Data and
information not Excepted data will be
On form . . . immediately made available . . .
available are . .
.
------------------------------------------------------------------------
(1) [Reserved] .................
(2) [Reserved] .................
(3) [Reserved] .................
(4) [Reserved] .................
(5) [Reserved] .................
(6) BOEM-0127, Sensitive Items 124 through 2 years after the
Reservoir Information Report, 168, effective date of
the Sensitive
Reservoir
Information Report.
(7) [Reserved] .................
(8) [Reserved] .................
(9) BOEM-0137 OCS Plan Items providing When the well goes on
Information, the bottomhole production or
location, true according to the
vertical depth, table in paragraph
and measured (b) of this section,
depth of wells, whichever is
earlier.
(10) BOEM-0140, Bottomhole All items, 2 years after the
Pressure Survey Report, date of the survey.
------------------------------------------------------------------------

(b) BOEM will release lease and permit data and information that you
submit and BOEM retains, but that are not normally submitted on BOEM
forms, according to the following table:

------------------------------------------------------------------------
Special
If . . . BOEM will release At this time . . provisions . .
. . . . .
------------------------------------------------------------------------
(1) The Director Geophysical data, At any time, BOEM will
determines that Geological data release data
data and Interpreted G&G and
information are information, information
needed for Processed G&G only if
specific information, release would
scientific or Analyzed further the
research geological National
purposes for the information, interest
Government, without unduly
damaging the
competitive
position of
the lessee.
(2) Data or Geophysical data, 60 days after BOEM will
information is Geological data, BOEM receives release the
collected with Interpreted G&G the data or data and
high-resolution information, information, if information
systems (e.g., Processed the Regional earlier than
bathymetry, side- geological Supervisor deems 60 days if the
scan sonar, information, it necessary, Regional
subbottom Analyzed Supervisor
profiler, and geological determines it
magnetometer) to information, is needed by
comply with affected
safety or States to make
environmental decisions
protection under subpart
requirements, B. The
Regional
Supervisor
will
reconsider
earlier
release if you
satisfy him/
her that it
would unduly
damage your
competitive
position.
(3) Your lease is Geophysical data, When your lease This release
no longer in Geological data, terminates, time applies
effect, Processed G&G only if the
information provisions in
Interpreted G&G this table
information, governing high-
Analyzed resolution
geological systems and
information, the provisions
in Sec.
552.7 do not
apply. The
release time
applies to the
geophysical
data and
information
only if
acquired
postlease for
a lessee's
exclusive use.
(4) Your lease is Geophysical data, 10 years after This release
still in effect, Processed you submit the time applies
geophysical data and only if the
information, information, provisions in
Interpreted G&G this table
information, governing high-
resolution
systems and
the provisions
in Sec.
552.7 do not
apply. This
release time
applies to the
geophysical
data and
information
only if
acquired
postlease for
a lessee's
exclusive use.

[[Page 369]]

(5) Your lease is Geological data, Two years after These release
still in effect analyzed the required times apply
and within the geological submittal date only if the
primary term information or 60 days after provisions in
specified in the a lease sale if this table
lease any portion of governing high-
an offered lease resolution
is within 50 systems and
miles of a well, the provisions
whichever is in Sec.
later 552.7 do not
apply. If the
primary term
specified in
the lease is
extended, this
provision
applies to the
extension.
(6) Your lease is Geological data, 2 years after the None.
in effect and Analyzed required
beyond the geological submittal date,
primary term information,
specified in the
lease,
(7) Data or Descriptions of When the well Directional
information is downhole goes on survey data
submitted on locations, production or may be
well operations, operations, and when geological released
equipment, data is released earlier to the
according to owner of an
Sec. Sec. adjacent lease
550.197(b)(5) according to
and (b)(6), 30 CFR 250
whichever occurs subpart D.
earlier,
(8) Data and Any data or At any time, None.
information are information
obtained from obtained,
beneath unleased
land as a result
of a well
deviation that
has not been
approved by the
Regional
Supervisor,
(9) Except for G&G data, Geological data None.
high-resolution analyzed and information:
data and geological 10 years after
information information, BOEM issues the
released under processed and permit;
paragraph (b)(2) interpreted G&G Geophysical
of this section information, data: 50 years
data and after BOEM
information issues the
acquired by a permit;
permit under 30 Geophysical
CFR part 551 are information: 25
submitted by a years after BOEM
lessee under issues the
part 550, 30 CFR permit,
part 203, or 30
CFR part 250,
------------------------------------------------------------------------

(c) BOEM may allow limited data and information inspection, but only
by a person with a direct interest in related BOEM decisions and issues
in a specific geographic area, and who agrees in writing to maintain the
confidentiality of geological and geophysical (G&G) data and information
submitted under this part that BOEM uses to:
(1) Promote operational safety;
(2) Protect the environment; or
(3) Make field determinations.
(d) No proprietary information received by BOEM under 43 U.S.C. 1352
will be transmitted to any affected State unless the lessee, or the
permittee and all persons to whom such permittee has sold such
information under promise of confidentiality, agree to such transmittal.

[76 FR 64623, Oct. 18, 2011, as amended at 81 FR 18152, Mar. 30, 2016]

References

Sec. 550.198 [Reserved]

Sec. 550.199 Paperwork Reduction Act statements--information collection.

(a) OMB has approved the information collection requirements in part
550 under 44 U.S.C. 3501 et seq. The table in paragraph (e) of this
section lists the subpart in the rule requiring the information and its
title, provides the OMB control number, and summarizes the reasons for
collecting the information and how BOEM uses the information. The
associated BOEM forms required by this part are listed at the end of
this table with the relevant information.
(b) Respondents are OCS oil, gas, and sulphur lessees and operators.
The requirement to respond to the information collections in this part
is mandated under the Act (43 U.S.C. 1331 et seq.) and the Act's
Amendments of 1978 (43 U.S.C. 1801 et seq.). Some responses are also
required to obtain or retain a benefit or may be voluntary. Proprietary
information will be protected under Sec. 550.197, Data and information
to

[[Page 370]]

be made available to the public or for limited inspection; parts 551,
552; and the Freedom of Information Act (5 U.S.C. 552) and its
implementing regulations at 43 CFR part 2.
(c) The Paperwork Reduction Act of 1995 requires us to inform the
public that an agency may not conduct or sponsor, and you are not
required to respond to, a collection of information unless it displays a
currently valid OMB control number.
(d) Send comments regarding any aspect of the collections of
information under this part, including suggestions for reducing the
burden, to the Information Collection Clearance Officer, Bureau of Ocean
Energy Management, 45600 Woodland Road, Sterling, VA 20166.
(e) BOEM is collecting this information for the reasons given in the
following table:

------------------------------------------------------------------------
30 CFR subpart, title and/or BOEM Form Reasons for collecting
(OMB Control No.) information and how used
------------------------------------------------------------------------
(1) Subpart A, General (1010-0114), To inform BOEM of actions taken
including Forms BOEM-1123, Designation to comply with general
of Operator and BOEM-1832, requirements on the OCS. To
Notification of Incidents of ensure that operations on the
Noncompliance. OCS meet statutory and
regulatory requirements, are
safe and protect the
environment, and result in
diligent exploration,
development, and production on
OCS leases. To support the
unproved and proved reserve
estimation, resource
assessment, and fair market
value determinations.
(2) Subpart B, Exploration and To inform BOEM, States, and the
Development and Production Plans (1010- public of planned exploration,
0151), including Forms BOEM-0137, OCS development, and production
Plan Information Form; BOEM-0138, EP operations on the OCS. To
Air Quality Screening Checklist; BOEM- ensure that operations on the
0139, DOCD Air Quality Screening OCS are planned to comply with
Checklist; BOEM-0141, ROV Survey statutory and regulatory
Report Form; and BOEM-0142, requirements, will be safe and
Environmental Impact Analysis protect the human, marine, and
Worksheet. coastal environment, and will
result in diligent
exploration, development, and
production of leases.
(3) Subpart C, Pollution Prevention and To inform BOEM of measures to
Control (1010-0057). be taken to prevent air
pollution. To ensure that
appropriate measures are taken
to prevent air pollution.
(4) Subpart J, Pipelines and Pipeline To provide BOEM with
Rights-of-Way (1010-0050), including information regarding the
Form BOEM-2030, Outer Continental design, installation, and
Shelf (OCS) Pipeline Right-of-Way operation of pipelines on the
Grant Bond. OCS. To ensure that pipeline
operations are safe and
protect the human, marine, and
coastal environment.
(5) Subpart K, Oil and Gas Production To inform BOEM of production
Rates (1010-0041), including Forms rates for hydrocarbons
BOEM-0127, Sensitive Reservoir produced on the OCS. To ensure
Information Report and BOEM-0140, economic maximization of
Bottomhole Pressure Survey Report. ultimate hydrocarbon recovery.
(6) Subpart N, Remedies and Penalties.. The requirements in subpart N
are exempt from the Paperwork
Reduction Act of 1995
according to 5 CFR 1320.4.
------------------------------------------------------------------------

[76 FR 64623, Oct. 18, 2011, as amended at 80 FR 57096, Sept. 22, 2015]

Subpart B_Plans and Information

General Information

Sec. 550.200 Definitions.

Acronyms and terms used in this subpart have the following meanings:
(a) Acronyms used frequently in this subpart are listed
alphabetically below:
BOEM means Bureau of Ocean Energy Management.
BSEE means Bureau of Safety and Environmental Enforcement.
CID means Conservation Information Document.
CZMA means Coastal Zone Management Act.
DOCD means Development Operations Coordination Document.
DPP means Development and Production Plan.
DWOP means Deepwater Operations Plan.
EIA means Environmental Impact Analysis.
EP means Exploration Plan.
IOP means Integrated Operations Plan.
NPDES means National Pollutant Discharge Elimination System.
NTL means Notice to Lessees and Operators.
OCS means Outer Continental Shelf.
(b) Terms used in this subpart are listed alphabetically below:

[[Page 371]]

Amendment means a change you make to an EP, DPP, or DOCD that is
pending before BOEM for a decision (see Sec. Sec. 550.232(d) and
550.267(d)).
Modification means a change required by the Regional Supervisor to
an EP, DPP, or DOCD (see Sec. 550.233(b)(2) and Sec. 550.270(b)(2))
that is pending before BOEM for a decision because the OCS plan is
inconsistent with applicable requirements.
New or unusual technology means equipment or procedures that:
(1) Have not been used previously or extensively in a BOEM OCS
Region;
(2) Have not been used previously under the anticipated operating
conditions; or
(3) Have operating characteristics that are outside the performance
parameters established by this part.
Non-conventional production or completion technology includes, but
is not limited to, floating production systems, tension leg platforms,
spars, floating production, storage, and offloading systems, guyed
towers, compliant towers, subsea manifolds, and other subsea production
components that rely on a remote site or host facility for utility and
well control services.
Offshore vehicle means a vehicle that is capable of being driven on
ice.
Resubmitted OCS plan means an EP, DPP, or DOCD that contains changes
you make to an OCS plan that BOEM has disapproved (see Sec. Sec.
550.234(b), 550.272(a), and 550.273(b)).
Revised OCS plan means an EP, DPP, or DOCD that proposes changes to
an approved OCS plan, such as those in the location of a well or
platform, type of drilling unit, or location of the onshore support base
(see Sec. 550.283(a)).
Supplemental OCS plan means an EP, DPP, or DOCD that proposes the
addition to an approved OCS plan of an activity that requires approval
of an application or permit (see Sec. 550.283(b)).

[76 FR 64623, Oct. 18, 2011, as amended at 81 FR 46565, July 15, 2016]

Sec. 550.201 What plans and information must I submit before I conduct
any activities on my lease or unit?

(a) Plans and documents. Before you conduct the activities on your
lease or unit listed in the following table, you must submit, and BOEM
must approve, the listed plans and documents. Your plans and documents
may cover one or more leases or units.

------------------------------------------------------------------------
You must submit a(n) . . . Before you . . .
------------------------------------------------------------------------
(1) Exploration Plan (EP), Conduct any exploration activities on a
lease or unit.
(2) Development and Conduct any development and production
Production Plan (DPP), activities on a lease or unit in any OCS
area other than the Western Gulf of
Mexico.
(3) Development Operations Conduct any development and production
Coordination Document activities on a lease or unit in the
(DOCD), Western GOM.
(4) BSEE approved Deepwater Conduct post-drilling installation
Operations Plan (DWOP), activities in any water depth associated
with a development project that will
involve the use of a non-conventional
production or completion technology.
(5) Conservation Information Commence production from development
Document (CID), projects in water depths greater than
1,312 feet (400 meters).
(6) EP, DPP, or DOCD, Conduct geological or geophysical (G&G)
exploration or a development G&G
activity (see definitions under Sec.
550.105) on your lease or unit when:
(i) It will result in a physical
penetration of the seabed greater than
500 feet (152 meters);
(ii) It will involve the use of
explosives;
(iii) The Regional Director determines
that it might have a significant adverse
effect on the human, marine, or coastal
environment; or
(iv) The Regional Supervisor, after
reviewing a notice under Sec. 550.209,
determines that an EP, DPP, or DOCD is
necessary.
------------------------------------------------------------------------

[[Page 372]]

(1) Sufficient applicable information or analysis is readily
available to BOEM;
(2) Other coastal or marine resources are not present or affected;
(3) Other factors such as technological advances affect information
needs; or
(4) Information is not necessary or required for a State to
determine consistency with their CZMA Plan.
(d) Referencing. In preparing your proposed plan or document, you
may reference information and data discussed in other plans or documents
you previously submitted or that are otherwise readily available to
BOEM.

Sec. 550.202 What criteria must the Exploration Plan (EP), Development
and Production Plan (DPP), or Development Operations Coordination Document
(DOCD) meet?

Your EP, DPP, or DOCD must demonstrate that you have planned and are
prepared to conduct the proposed activities in a manner that:
(a) Conforms to the Outer Continental Shelf Lands Act as amended
(Act), applicable implementing regulations, lease provisions and
stipulations, and other Federal laws;
(b) Is safe;
(c) Conforms to sound conservation practices and protects the rights
of the lessor;
(d) Does not unreasonably interfere with other uses of the OCS,
including those involved with National security or defense; and
(e) Does not cause undue or serious harm or damage to the human,
marine, or coastal environment.

Sec. 550.203 Where can wells be located under an EP, DPP, or DOCD?

The Regional Supervisor reviews and approves proposed well location
and spacing under an EP, DPP, or DOCD. In deciding whether to approve a
proposed well location and spacing, the Regional Supervisor will
consider factors including, but not limited to, the following:
(a) Protecting correlative rights;
(b) Protecting Federal royalty interests;
(c) Recovering optimum resources;
(d) Number of wells that can be economically drilled for proper
reservoir management;
(e) Location of drilling units and platforms;
(f) Extent and thickness of the reservoir;
(g) Geologic and other reservoir characteristics;
(h) Minimizing environmental risk;
(i) Preventing unreasonable interference with other uses of the OCS;
and
(j) Drilling of unnecessary wells.

Sec. 550.204 When must I submit my IOP for proposed Arctic exploratory
drilling operations and what must the IOP include?

If you propose exploratory drilling activities on the Arctic OCS,
you must submit an Integrated Operations Plan (IOP) to the Regional
Supervisor at least 90 days prior to filing your EP. Your IOP must
describe how your exploratory drilling program will be designed and
conducted in an integrated manner that accounts for Arctic OCS
conditions and include the following information:
(a) A description of how all vessels and equipment will be designed,
built, and/or modified to account for Arctic OCS conditions;
(b) A schedule of your exploratory drilling program, including
contractor work on critical components of your program;
(c) A description of your mobilization and demobilization
operations, including tow plans that account for Arctic OCS conditions,
as well as your general maintenance schedule for vessels and equipment;
(d) A description of your exploratory drilling program objectives
and timelines for each objective, including general plans for
abandonment of the well(s), such as:
(1) Contingency plans for temporary abandonment in the event of ice
encroachment at the drill site;
(2) Plans for permanent abandonment; and
(3) Plans for temporary seasonal abandonment.
(e) A description of your weather and ice forecasting capabilities
for all phases of the exploration program, including a description of
how you would respond to and manage ice hazards and weather events;
(f) A description of work to be performed by contractors supporting
your

[[Page 373]]

exploration drilling program (including mobilization and
demobilization), including:
(1) How such work will be designed or modified to account for Arctic
OCS conditions; and
(2) Your concepts for contractor management, oversight, and risk
management.
(g) A description of how you will ensure operational safety while
working in Arctic OCS conditions, including but not limited to:
(1) The safety principles that you intend to apply to yourself and
your contractors;
(2) The accountability structure within your organization for
implementing such principles;
(3) How you will communicate such principles to your employees and
contractors; and
(4) How you will determine successful implementation of such
principles.
(h) Information regarding your preparations and plans for staging of
oil spill response assets;
(i) A description of your efforts to minimize impacts of your
exploratory drilling operations on local community infrastructure,
including but not limited to housing, energy supplies, and services; and
(j) A description of whether and to what extent your project will
rely on local community workforce and spill cleanup response capacity.

[81 FR 46565, July 15, 2016]

Sec. 550.205 [Reserved]

Sec. 550.206 How do I submit the IOP, EP, DPP, or DOCD?

(a) Number of copies. When you submit an IOP, EP, DPP, or DOCD to
BOEM, you must provide:
(1) Four copies that contain all required information (proprietary
copies);
(2) Eight copies for public distribution (public information copies)
that omit information that you assert is exempt from disclosure under
the Freedom of Information Act (FOIA) (5 U.S.C. 552) and the
implementing regulations (43 CFR part 2); and
(3) Any additional copies that may be necessary to facilitate review
of the IOP, EP, DPP, or DOCD by certain affected States and other
reviewing entities.
(b) Electronic submission. You may submit part or all of your IOP,
EP, DPP, or DOCD and its accompanying information electronically. If you
prefer to submit your IOP, EP, DPP, or DOCD electronically, ask the
Regional Supervisor for further guidance.
(c) Withdrawal after submission. You may withdraw your proposed IOP,
EP, DPP, or DOCD at any time for any reason. Notify the appropriate BOEM
OCS Region if you do.

[81 FR 46565, July 15, 2016]

Ancillary Activities

Sec. 550.207 What ancillary activities may I conduct?

Before or after you submit an EP, DPP, or DOCD to BOEM, you may
elect, the regulations in this part may require, or the Regional
Supervisor may direct you to conduct ancillary activities. Ancillary
activities include:
(a) Geological and geophysical (G&G) explorations and development
G&G activities;
(b) Geological and high-resolution geophysical, geotechnical,
archaeological, biological, physical oceanographic, meteorological,
socioeconomic, or other surveys; or
(c) Studies that model potential oil and hazardous substance spills,
drilling muds and cuttings discharges, projected air emissions, or
potential hydrogen sulfide (H2S) releases.

Sec. 550.208 If I conduct ancillary activities, what notices must I provide?

At least 30 calendar days before you conduct any G&G exploration or
development G&G activity (see Sec. 550.207(a)), you must notify the
Regional Supervisor in writing.
(a) When you prepare the notice, you must:
(1) Sign and date the notice;
(2) Provide the names of the vessel, its operator, and the person(s)
in charge; the specific type(s) of operations you will conduct; and the
instrumentation/techniques and vessel navigation system you will use;
(3) Provide expected start and completion dates and the location of
the activity; and

[[Page 374]]

(4) Describe the potential adverse environmental effects of the
proposed activity and any mitigation to eliminate or minimize these
effects on the marine, coastal, and human environment.
(b) The Regional Supervisor may require you to:
(1) Give written notice to BOEM at least 15 calendar days before you
conduct any other ancillary activity (see Sec. 550.207(b) and (c)) in
addition to those listed in Sec. 550.207(a); and
(2) Notify other users of the OCS before you conduct any ancillary
activity.

Sec. 550.209 What is the BOEM review process for the notice?

The Regional Supervisor will review any notice required under Sec.
550.208(a) and (b)(1) to ensure that your ancillary activity complies
with the performance standards listed in Sec. 550.202(a), (b), (d), and
(e). The Regional Supervisor may notify you that your ancillary activity
does not comply with those standards. In such a case, the Regional
Supervisor will require you to submit an EP, DPP, or DOCD and you may
not start your ancillary activity until the Regional Supervisor approves
the EP, DPP, or DOCD.

Sec. 550.210 If I conduct ancillary activities, what reporting
and data/information retention requirements must I satisfy?

(a) Reporting. The Regional Supervisor may require you to prepare
and submit reports that summarize and analyze data or information
obtained or derived from your ancillary activities. When applicable,
BOEM will protect and disclose the data and information in these reports
in accordance with Sec. 550.197(b).
(b) Data and information retention. You must retain copies of all
original data and information, including navigation data, obtained or
derived from your G&G explorations and development G&G activities (see
Sec. 550.207(a)), including any such data and information you obtained
from previous leaseholders or unit operators. You must submit such data
and information to BOEM for inspection and possible retention upon
request at any time before lease or unit termination. When applicable,
BOEM will protect and disclose such submitted data and information in
accordance with Sec. 550.197(b).

Contents of Exploration Plans (EP)

Sec. 550.211 What must the EP include?

Your EP must include the following:
(a) Description, objectives, and schedule. A description, discussion
of the objectives, and tentative schedule (from start to completion) of
the exploration activities that you propose to undertake. Examples of
exploration activities include exploration drilling, well test flaring,
installing a well protection structure, and temporary well abandonment.
(b) Location. A map showing the surface location and water depth of
each proposed well and the locations of all associated drilling unit
anchors.
(c) Drilling unit. A description of the drilling unit and associated
equipment you will use to conduct your proposed exploration activities,
including a brief description of its important safety and pollution
prevention features, and a table indicating the type and the estimated
maximum quantity of fuels, oil, and lubricants that will be stored on
the facility (see definition of ``facility'' under Sec. 550.105(3)).
(d) Service fee. You must include payment of the service fee listed
in Sec. 550.125.

Sec. 550.212 What information must accompany the EP?

The following information must accompany your EP:
(a) General information required by Sec. 550.213;
(b) Geological and geophysical (G&G) information required by Sec.
550.214;
(c) Hydrogen sulfide information required by Sec. 550.215;
(d) Biological, physical, and socioeconomic information required by
Sec. 550.216;
(e) Solid and liquid wastes and discharges information and cooling
water intake information required by Sec. 550.217;
(f) Air emissions information required by Sec. 550.218;
(g) Oil and hazardous substance spills information required by Sec.
550.219;

[[Page 375]]

(h) Alaska planning information required by Sec. 550.220;
(i) Environmental monitoring information required by Sec. 550.221;
(j) Lease stipulations information required by Sec. 550.222;
(k) Mitigation measures information required by Sec. 550.223;
(l) Support vessels and aircraft information required by Sec.
550.224;
(m) Onshore support facilities information required by Sec.
550.225;
(n) Coastal zone management information required by Sec. 550.226;
(o) Environmental impact analysis information required by Sec.
550.227; and
(p) Administrative information required by Sec. 550.228.

Sec. 550.213 What general information must accompany the EP?

The following general information must accompany your EP:
(a) Applications and permits. A listing, including filing or
approval status, of the Federal, State, and local application approvals
or permits you must obtain to conduct your proposed exploration
activities.
(b) Drilling fluids. A table showing the projected amount, discharge
rate, and chemical constituents for each type (i.e., water-based, oil-
based, synthetic-based) of drilling fluid you plan to use to drill your
proposed exploration wells.
(c) Chemical products. A table showing the name and brief
description, quantities to be stored, storage method, and rates of usage
of the chemical products you will use to conduct your proposed
exploration activities. List only those chemical products you will store
or use in quantities greater than the amounts defined as Reportable
Quantities in 40 CFR part 302, or amounts specified by the Regional
Supervisor.
(d) New or unusual technology. A description and discussion of any
new or unusual technology (see definition under Sec. 550.200) you will
use to carry out your proposed exploration activities. In the public
information copies of your EP, you may exclude any proprietary
information from this description. In that case, include a brief
discussion of the general subject matter of the omitted information. If
you will not use any new or unusual technology to carry out your
proposed exploration activities, include a statement so indicating.
(e) Bonds, oil spill financial responsibility, and well control
statements. Statements attesting that:
(1) The activities and facilities proposed in your EP are or will be
covered by an appropriate bond under 30 CFR part 556, subpart I;
(2) You have demonstrated or will demonstrate oil spill financial
responsibility for facilities proposed in your EP according to 30 CFR
part 553; and
(3) You have or will have the financial capability to drill a relief
well and conduct other emergency well control operations.
(f) Suspensions of operations. A brief discussion of any suspensions
of operations that you anticipate may be necessary in the course of
conducting your activities under the EP.
(g) Blowout scenario. A scenario for the potential blowout of the
proposed well in your EP that you expect will have the highest volume of
liquid hydrocarbons. Include the estimated flow rate, total volume, and
maximum duration of the potential blowout. Also, discuss the potential
for the well to bridge over, the likelihood for surface intervention to
stop the blowout, the availability of a rig to drill a relief well, and
rig package constraints. Estimate the time it would take to drill a
relief well.
(h) Contact. The name, address (e-mail address, if available), and
telephone number of the person with whom the Regional Supervisor and any
affected State(s) can communicate about your EP.

Sec. 550.214 What geological and geophysical (G&G) information
must accompany the EP?

The following G&G information must accompany your EP:
(a) Geological description. A geological description of the
prospect(s).
(b) Structure contour maps. Current structure contour maps (depth-
based, expressed in feet subsea) drawn on the top of each prospective
hydrocarbon-bearing reservoir showing the locations of proposed wells.
(c) Two-dimensional (2-D) or three-dimensional (3-D) seismic lines.
Copies of migrated and annotated 2-D or 3-D

[[Page 376]]

seismic lines (with depth scale) intersecting at or near your proposed
well locations. You are not required to conduct both 2-D and 3-D seismic
surveys if you choose to conduct only one type of survey. If you have
conducted both types of surveys, the Regional Supervisor may instruct
you to submit the results of both surveys. You must interpret and
display this information. Because of its volume, provide this
information as an enclosure to only one proprietary copy of your EP.
(d) Geological cross-sections. Interpreted geological cross-sections
showing the location and depth of each proposed well.
(e) Shallow hazards report. A shallow hazards report based on
information obtained from a high-resolution geophysical survey, or a
reference to such report if you have already submitted it to the
Regional Supervisor.
(f) Shallow hazards assessment. For each proposed well, an
assessment of any seafloor and subsurface geological and manmade
features and conditions that may adversely affect your proposed drilling
operations.
(g) High-resolution seismic lines. A copy of the high-resolution
survey line closest to each of your proposed well locations. Because of
its volume, provide this information as an enclosure to only one
proprietary copy of your EP. You are not required to provide this
information if the surface location of your proposed well has been
approved in a previously submitted EP, DPP, or DOCD.
(h) Stratigraphic column. A generalized biostratigraphic/
lithostratigraphic column from the surface to the total depth of the
prospect.
(i) Time-versus-depth chart. A seismic travel time-versus-depth
chart based on the appropriate velocity analysis in the area of
interpretation and specifying the geodetic datum.
(j) Geochemical information. A copy of any geochemical reports you
used or generated.
(k) Future G&G activities. A brief description of the types of G&G
explorations and development G&G activities you may conduct for lease or
unit purposes after your EP is approved.

Sec. 550.215 What hydrogen sulfide (H [bdi2]S) information
must accompany the EP?

The following H2S information, as applicable, must
accompany your EP:
(a) Concentration. The estimated concentration of any H2S
you might encounter while you conduct your proposed exploration
activities.
(b) Classification. Under 30 CFR 250.490(c), a request that the BSEE
Regional Supervisor classify the area of your proposed exploration
activities as either H2S absent, H2S present, or
H2S unknown. Provide sufficient information to justify your
request.
(c) H2S Contingency Plan. If you ask the Regional
Supervisor to classify the area of your proposed exploration activities
as either H2S present or H2S unknown, an
H2S Contingency Plan prepared under 30 CFR 250.490(f), or a
reference to an approved or submitted H2S Contingency Plan
that covers the proposed exploration activities.
(d) Modeling report. If you modeled a potential H2S
release when developing your EP, modeling report or the modeling
results, or a reference to such report or results if you have already
submitted it to the Regional Supervisor.
(1) The analysis in the modeling report must be specific to the
particular site of your proposed exploration activities, and must
consider any nearby human-occupied OCS facilities, shipping lanes,
fishery areas, and other points where humans may be subject to potential
exposure from an H2S release from your proposed exploration
activities.
(2) If any H2S emissions are projected to affect an
onshore location in concentrations greater than 10 parts per million,
the modeling analysis must be consistent with the Environmental
Protection Agency's (EPA) risk management plan methodologies outlined in
40 CFR part 68.

Sec. 550.216 What biological, physical, and socioeconomic information
must accompany the EP?

If you obtain the following information in developing your EP, or if
the Regional Supervisor requires you to obtain it, you must include a
report, or the information obtained, or a reference to such a report or
information

[[Page 377]]

if you have already submitted it to the Regional Supervisor, as
accompanying information:
(a) Biological environment reports. Site-specific information on
chemosynthetic communities, federally listed threatened or endangered
species, marine mammals protected under the Marine Mammal Protection Act
(MMPA), sensitive underwater features, marine sanctuaries, critical
habitat designated under the Endangered Species Act (ESA), or other
areas of biological concern.
(b) Physical environment reports. Site-specific meteorological,
physical oceanographic, geotechnical reports, or archaeological reports
(if required under Sec. 550.194).
(c) Socioeconomic study reports. Socioeconomic information regarding
your proposed exploration activities.

Sec. 550.217 What solid and liquid wastes and discharges information
and cooling water intake information must accompany the EP?

The following solid and liquid wastes and discharges information and
cooling water intake information must accompany your EP:
(a) Projected wastes. A table providing the name, brief description,
projected quantity, and composition of solid and liquid wastes (such as
spent drilling fluids, drill cuttings, trash, sanitary and domestic
wastes, and chemical product wastes) likely to be generated by your
proposed exploration activities. Describe:
(1) The methods you used for determining this information; and
(2) Your plans for treating, storing, and downhole disposal of these
wastes at your drilling location(s).
(b) Projected ocean discharges. If any of your solid and liquid
wastes will be discharged overboard, or are planned discharges from
manmade islands:
(1) A table showing the name, projected amount, and rate of
discharge for each waste type; and
(2) A description of the discharge method (such as shunting through
a downpipe, etc.) you will use.
(c) National Pollutant Discharge Elimination System (NPDES) permit.
(1) A discussion of how you will comply with the provisions of the
applicable general NPDES permit that covers your proposed exploration
activities; or
(2) A copy of your application for an individual NPDES permit.
Briefly describe the major discharges and methods you will use for
compliance.
(d) Modeling report. The modeling report or the modeling results (if
you modeled the discharges of your projected solid or liquid wastes when
developing your EP), or a reference to such report or results if you
have already submitted it to the Regional Supervisor.
(e) Projected cooling water intake. A table for each cooling water
intake structure likely to be used by your proposed exploration
activities that includes a brief description of the cooling water intake
structure, daily water intake rate, water intake through screen
velocity, percentage of water intake used for cooling water, mitigation
measures for reducing impingement and entrainment of aquatic organisms,
and biofouling prevention measures.

Sec. 550.218 What air emissions information must accompany the EP?

The following air emissions information, as applicable, must
accompany your EP:
(a) Projected emissions. Tables showing the projected emissions of
sulphur dioxide (SO2), particulate matter in the form of
PM10 and PM2.5 when applicable, nitrogen oxides
(NOX), carbon monoxide (CO), and volatile organic compounds
(VOC) that will be generated by your proposed exploration activities.
(1) For each source on or associated with the drilling unit
(including well test flaring and well protection structure
installation), you must list:
(i) The projected peak hourly emissions;
(ii) The total annual emissions in tons per year;
(iii) Emissions over the duration of the proposed exploration
activities;
(iv) The frequency and duration of emissions; and
(v) The total of all emissions listed in paragraphs (a)(1)(i)
through (iv) of this section.
(2) You must provide the basis for all calculations, including
engine size and rating, and applicable operational information.

[[Page 378]]

(3) You must base the projected emissions on the maximum rated
capacity of the equipment on the proposed drilling unit under its
physical and operational design.
(4) If the specific drilling unit has not yet been determined, you
must use the maximum emission estimates for the type of drilling unit
you will use.
(b) Emission reduction measures. A description of any proposed
emission reduction measures, including the affected source(s), the
emission reduction control technologies or procedures, the quantity of
reductions to be achieved, and any monitoring system you propose to use
to measure emissions.
(c) Processes, equipment, fuels, and combustibles. A description of
processes, processing equipment, combustion equipment, fuels, and
storage units. You must include the characteristics and the frequency,
duration, and maximum burn rate of any well test fluids to be burned.
(d) Distance to shore. Identification of the distance of your
drilling unit from the mean high water mark (mean higher high water mark
on the Pacific coast) of the adjacent State.
(e) Non-exempt drilling units. A description of how you will comply
with Sec. 550.303 when the projected emissions of SO2, PM,
NOX, CO, or VOC, that will be generated by your proposed
exploration activities, are greater than the respective emission
exemption amounts ``E'' calculated using the formulas in Sec.
550.303(d). When BOEM requires air quality modeling, you must use the
guidelines in Appendix W of 40 CFR part 51 with a model approved by the
Director. Submit the best available meteorological information and data
consistent with the model(s) used.
(f) Modeling report. A modeling report or the modeling results (if
Sec. 550.303 requires you to use an approved air quality model to model
projected air emissions in developing your EP), or a reference to such a
report or results if you have already submitted it to the Regional
Supervisor.

Sec. 550.219 What oil and hazardous substance spills information
must accompany the EP?

The following information regarding potential spills of oil (see
definition under 30 CFR 254.6) and hazardous substances (see definition
under 40 CFR part 116) as applicable, must accompany your EP:
(a) Oil spill response planning. The material required under
paragraph (a)(1) or (a)(2) of this section:
(1) An Oil Spill Response Plan (OSRP) for the facilities you will
use to conduct your exploration activities prepared according to the
requirements of 30 CFR part 254, subpart B; or
(2) Reference to your approved regional OSRP (see 30 CFR 254.3) to
include:
(i) A discussion of your regional OSRP;
(ii) The location of your primary oil spill equipment base and
staging area;
(iii) The name(s) of your oil spill removal organization(s) for both
equipment and personnel;
(iv) The calculated volume of your worst case discharge scenario
(see 30 CFR 254.26(a)), and a comparison of the appropriate worst case
discharge scenario in your approved regional OSRP with the worst case
discharge scenario that could result from your proposed exploration
activities; and
(v) A description of the worst case discharge scenario that could
result from your proposed exploration activities (see 30 CFR 254.26(b),
(c), (d), and (e)).
(b) Modeling report. If you model a potential oil or hazardous
substance spill in developing your EP, a modeling report or the modeling
results, or a reference to such report or results if you have already
submitted it to the Regional Supervisor.

Sec. 550.220 If I propose activities in the Alaska OCS Region,
what planning information must accompany the EP?

If you propose exploration activities in the Alaska OCS Region, the
following planning information must accompany your EP:
(a) Emergency plans. A description of your emergency plans to
respond to a fire, explosion, personnel evacuation,

[[Page 379]]

or loss of well control, as well as a loss or disablement of a drilling
unit, and loss of or damage to a support vessel, offshore vehicle, or
aircraft.
(b) Critical operations and curtailment procedures. Critical
operations and curtailment procedures for your exploration activities.
The procedures must identify ice conditions, weather, and other
constraints under which the exploration activities will either be
curtailed or not proceed.
(c) If you propose exploration activities on the Arctic OCS, the
following planning information must also accompany your EP:
(1) Suitability for Arctic OCS conditions. A description of how your
exploratory drilling activities will be designed and conducted in a
manner that accounts for Arctic OCS conditions and how such activities
will be managed and overseen as an integrated endeavor.
(2) Ice and weather management. A description of your weather and
ice forecasting and management plans for all phases of your exploratory
drilling activities, including:
(i) A description of how you will respond to and manage ice hazards
and weather events;
(ii) Your ice and weather alert procedures;
(iii) Your procedures and thresholds for activating your ice and
weather management system(s); and
(iv) Confirmation that you will operate ice and weather management
and alert systems continuously throughout the planned operations,
including mobilization and demobilization operations to and from the
Arctic OCS.
(3) Source control and containment equipment capabilities. A general
description of how you will comply with Sec. 250.471 of this title.
(4) Deployment of a relief well rig. A general description of how
you will comply with Sec. 250.472 of this title, including a
description of the relief well rig, the anticipated staging area of the
relief well rig, an estimate of the time it would take for the relief
well rig to arrive at the site of a loss of well control, how you would
drill a relief well if necessary, and the approximate timeframe to
complete relief well operations.
(5) Resource-sharing. Any agreements you have with third parties for
the sharing of assets or the provision of mutual aid in the event of an
oil spill or other emergency.
(6) Anticipated end of seasonal operations dates. Your projected end
of season dates, and the information used to identify those dates, for:
(i) The completion of on-site operations, which is contingent upon
your capability in terms of equipment and procedures to manage and
mitigate risks associated with Arctic OCS conditions; and
(ii) The termination of drilling operations consistent with the
relief rig planning requirements under Sec. 250.472 of this title and
with your estimated timeframe under paragraph (c)(4) of this section for
completion of relief well operations.

[76 FR 64623, Oct. 18, 2011, as amended at 81 FR 46565, July 15, 2016]

Sec. 550.221 What environmental monitoring information must accompany the EP?

The following environmental monitoring information, as applicable,
must accompany your EP:
(a) Monitoring systems. A description of any existing and planned
monitoring systems that are measuring, or will measure, environmental
conditions or will provide project-specific data or information on the
impacts of your exploration activities.
(b) Incidental takes. If there is reason to believe that protected
species may be incidentally taken by planned exploration activities, you
must describe how you will monitor for incidental take of:
(1) Threatened and endangered species listed under the ESA; and
(2) Marine mammals, as appropriate, if you have not already received
authorization for incidental take as may be necessary under the MMPA.
(c) Flower Garden Banks National Marine Sanctuary (FGBNMS). If you
propose to conduct exploration activities within the protective zones of
the FGBNMS, a description of your provisions for monitoring the impacts
of an oil spill on the environmentally sensitive resources at the
FGBNMS.

[[Page 380]]

Sec. 550.222 What lease stipulations information must accompany the EP?

A description of the measures you took, or will take, to satisfy the
conditions of lease stipulations related to your proposed exploration
activities must accompany your EP.

Sec. 550.223 What mitigation measures information must accompany the EP?

(a) If you propose to use any measures beyond those required by the
regulations in this part to minimize or mitigate environmental impacts
from your proposed exploration activities, a description of the measures
you will use must accompany your EP.
(b) If there is reason to believe that protected species may be
incidentally taken by planned exploration activities, you must include
mitigation measures designed to avoid or minimize the incidental take
of:
(1) Threatened and endangered species listed under the ESA; and
(2) Marine mammals, as appropriate, if you have not already received
authorization for incidental take as may be necessary under the MMPA.

Sec. 550.224 What information on support vessels, offshore vehicles,
and aircraft you will use must accompany the EP?

The following information on the support vessels, offshore vehicles,
and aircraft you will use must accompany your EP:
(a) General. A description of the crew boats, supply boats, anchor
handling vessels, tug boats, barges, ice management vessels, other
vessels, offshore vehicles, and aircraft you will use to support your
exploration activities. The description of vessels and offshore vehicles
must estimate the storage capacity of their fuel tanks and the frequency
of their visits to your drilling unit.
(b) Air emissions. A table showing the source, composition,
frequency, and duration of the air emissions likely to be generated by
the support vessels, offshore vehicles, and aircraft you will use that
will operate within 25 miles of your drilling unit.
(c) Drilling fluids and chemical products transportation. A
description of the transportation method and quantities of drilling
fluids and chemical products (see Sec. 550.213(b) and (c)) you will
transport from the onshore support facilities you will use to your
drilling unit.
(d) Solid and liquid wastes transportation. A description of the
transportation method and a brief description of the composition,
quantities, and destination(s) of solid and liquid wastes (see Sec.
550.217(a)) you will transport from your drilling unit.
(e) Vicinity map. A map showing the location of your proposed
exploration activities relative to the shoreline. The map must depict
the primary route(s) the support vessels and aircraft will use when
traveling between the onshore support facilities you will use and your
drilling unit.

Sec. 550.225 What information on the onshore support facilities you will use
must accompany the EP?

The following information on the onshore support facilities you will
use must accompany your EP:
(a) General. A description of the onshore facilities you will use to
provide supply and service support for your proposed exploration
activities (e.g., service bases and mud company docks).
(1) Indicate whether the onshore support facilities are existing, to
be constructed, or to be expanded.
(2) If the onshore support facilities are, or will be, located in
areas not adjacent to the Western GOM, provide a timetable for acquiring
lands (including rights-of-way and easements) and constructing or
expanding the facilities. Describe any State or Federal permits or
approvals (dredging, filling, etc.) that would be required for
constructing or expanding them.
(b) Air emissions. A description of the source, composition,
frequency, and duration of the air emissions (attributable to your
proposed exploration activities) likely to be generated by the onshore
support facilities you will use.
(c) Unusual solid and liquid wastes. A description of the quantity,
composition, and method of disposal of any unusual solid and liquid
wastes (attributable to your proposed exploration activities) likely to
be generated by the onshore support facilities you will use. Unusual
wastes are those wastes not specifically addressed in the relevant

[[Page 381]]

National Pollution Discharge Elimination System (NPDES) permit.
(d) Waste disposal. A description of the onshore facilities you will
use to store and dispose of solid and liquid wastes generated by your
proposed exploration activities (see Sec. 550.217) and the types and
quantities of such wastes.

Sec. 550.226 What Coastal Zone Management Act (CZMA) information
must accompany the EP?

The following CZMA information must accompany your EP:
(a) Consistency certification. A copy of your consistency
certification under section 307(c)(3)(B) of the CZMA (16 U.S.C.
1456(c)(3)(B)) and 15 CFR 930.76(d) stating that the proposed
exploration activities described in detail in this EP comply with (name
of State(s)) approved coastal management program(s) and will be
conducted in a manner that is consistent with such program(s); and
(b) Other information. ``Information'' as required by 15 CFR
930.76(a) and 15 CFR 930.58(a)(2)) and ``Analysis'' as required by 15
CFR 930.58(a)(3).

Sec. 550.227 What environmental impact analysis (EIA) information
must accompany the EP?

The following EIA information must accompany your EP:
(a) General requirements. Your EIA must:
(1) Assess the potential environmental impacts of your proposed
exploration activities;
(2) Be project specific; and
(3) Be as detailed as necessary to assist the Regional Supervisor in
complying with the National Environmental Policy Act (NEPA) of 1969 (42
U.S.C. 4321 et seq.) and other relevant Federal laws such as the ESA and
the MMPA.
(b) Resources, conditions, and activities. Your EIA must describe
those resources, conditions, and activities listed below that could be
affected by your proposed exploration activities, or that could affect
the construction and operation of facilities or structures, or the
activities proposed in your EP.
(1) Meteorology, oceanography, geology, and shallow geological or
manmade hazards;
(2) Air and water quality;
(3) Benthic communities, marine mammals, sea turtles, coastal and
marine birds, fish and shellfish, and plant life;
(4) Threatened or endangered species and their critical habitat as
defined by the Endangered Species Act of 1973;
(5) Sensitive biological resources or habitats such as essential
fish habitat, refuges, preserves, special management areas identified in
coastal management programs, sanctuaries, rookeries, and calving
grounds;
(6) Archaeological resources;
(7) Socioeconomic resources including employment, existing offshore
and coastal infrastructure (including major sources of supplies,
services, energy, and water), land use, subsistence resources and
harvest practices, recreation, recreational and commercial fishing
(including typical fishing seasons, location, and type), minority and
lower income groups, and coastal zone management programs;
(8) Coastal and marine uses such as military activities, shipping,
and mineral exploration or development; and
(9) Other resources, conditions, and activities identified by the
Regional Supervisor.
(c) Environmental impacts. Your EIA must:
(1) Analyze the potential direct and indirect impacts (including
those from accidents, cooling water intake structures, and those
identified in relevant ESA biological opinions such as, but not limited
to, those from noise, vessel collisions, and marine trash and debris)
that your proposed exploration activities will have on the identified
resources, conditions, and activities;
(2) Analyze any potential cumulative impacts from other activities
to those identified resources, conditions, and activities potentially
impacted by your proposed exploration activities;
(3) Describe the type, severity, and duration of these potential
impacts and their biological, physical, and other consequences and
implications;
(4) Describe potential measures to minimize or mitigate these
potential impacts; and
(5) Summarize the information you incorporate by reference.

[[Page 382]]

(d) Consultation. Your EIA must include a list of agencies and
persons with whom you consulted, or with whom you will be consulting,
regarding potential impacts associated with your proposed exploration
activities.
(e) References cited. Your EIA must include a list of the references
that you cite in the EIA.

Sec. 550.228 What administrative information must accompany the EP?

The following administrative information must accompany your EP:
(a) Exempted information description (public information copies
only). A description of the general subject matter of the proprietary
information that is included in the proprietary copies of your EP or its
accompanying information.
(b) Bibliography. (1) If you reference a previously submitted EP,
DPP, DOCD, study report, survey report, or other material in your EP or
its accompanying information, a list of the referenced material; and
(2) The location(s) where the Regional Supervisor can inspect the
cited referenced material if you have not submitted it.

Review and Decision Process for the EP

Sec. 550.231 After receiving the EP, what will BOEM do?

(a) Determine whether deemed submitted. Within 15 working days after
receiving your proposed EP and its accompanying information, the
Regional Supervisor will review your submission and deem your EP
submitted if:
(1) The submitted information, including the information that must
accompany the EP (refer to the list in Sec. 550.212), fulfills
requirements and is sufficiently accurate;
(2) You have provided all needed additional information (see Sec.
550.201(b)); and
(3) You have provided the required number of copies (see Sec.
550.206(a)).
(b) Identify problems and deficiencies. If the Regional Supervisor
determines that you have not met one or more of the conditions in
paragraph (a) of this section, the Regional Supervisor will notify you
of the problem or deficiency within 15 working days after the Regional
Supervisor receives your EP and its accompanying information. The
Regional Supervisor will not deem your EP submitted until you have
corrected all problems or deficiencies identified in the notice.
(c) Deemed submitted notification. The Regional Supervisor will
notify you when the EP is deemed submitted.

Sec. 550.232 What actions will BOEM take after the EP is deemed submitted?

(a) State and CZMA consistency reviews. Within 2 working days after
deeming your EP submitted under Sec. 550.231, the Regional Supervisor
will use receipted mail or alternative method to send a public
information copy of the EP and its accompanying information to the
following:
(1) The Governor of each affected State. The Governor has 21
calendar days after receiving your deemed-submitted EP to submit
comments. The Regional Supervisor will not consider comments received
after the deadline.
(2) The CZMA agency of each affected State. The CZMA consistency
review period under section 307(c)(3)(B)(ii) of the CZMA (16 U.S.C.
1456(c)(3)(B)(ii)) and 15 CFR 930.78 begins when the State's CZMA agency
receives a copy of your deemed-submitted EP, consistency certification,
and required necessary data and information (see 15 CFR 930.77(a)(1)).
(b) BOEM compliance review. The Regional Supervisor will review the
exploration activities described in your proposed EP to ensure that they
conform to the performance standards in Sec. 550.202.
(c) BOEM environmental impact evaluation. The Regional Supervisor
will evaluate the environmental impacts of the activities described in
your proposed EP and prepare environmental documentation under the
National Environmental Policy Act (NEPA) (42 U.S.C. 4321 et seq.) and
the implementing regulations (40 CFR parts 1500 through 1508).
(d) Amendments. During the review of your proposed EP, the Regional
Supervisor may require you, or you may elect, to change your EP. If you
elect to amend your EP, the Regional Supervisor may determine that your
EP, as

[[Page 383]]

amended, is subject to the requirements of Sec. 550.231.

Sec. 550.233 What decisions will BOEM make on the EP
and within what timeframe?

(a) Timeframe. The Regional Supervisor will take one of the actions
shown in the table in paragraph (b) of this section within 30 calendar
days after the Regional Supervisor deems your EP submitted under Sec.
550.231, or receives the last amendment to your proposed EP, whichever
occurs later.
(b) BOEM decision. By the deadline in paragraph (a) of this section,
the Regional Supervisor will take one of the following actions:

----------------------------------------------------------------------------------------------------------------
The regional supervisor will
. . . If . . . And then . . .
----------------------------------------------------------------------------------------------------------------
(1) Approve your EP, It complies with all applicable requirements, The Regional Supervisor will
notify you in writing of the
decision and may require you to
meet certain conditions,
including those to provide
monitoring information.
(2) Require you to modify The Regional Supervisor finds that it is The Regional Supervisor will
your proposed EP, inconsistent with the lease, the Act, the notify you in writing of the
regulations prescribed under the Act, or decision and describe the
other Federal laws, modifications you must make to
your proposed EP to ensure it
complies with all applicable
requirements.
(3) Disapprove your EP, Your proposed activities would probably cause (i) The Regional Supervisor will
serious harm or damage to life (including notify you in writing of the
fish or other aquatic life); property; any decision and describe the
mineral (in areas leased or not leased); the reason(s) for disapproving your
National security or defense; or the marine, EP.
coastal, or human environment; and you cannot (ii) BOEM may cancel your lease
modify your proposed activities to avoid such and compensate you under 43
condition(s), U.S.C. 1334(a)(2)(C) and the
implementing regulations in Sec.
Sec. 550.182, 550.184, and
550.185 and 30 CFR 556.77.
----------------------------------------------------------------------------------------------------------------

Sec. 550.234 How do I submit a modified EP or resubmit a disapproved EP,
and when will BOEM make a decision?

(a) Modified EP. If the Regional Supervisor requires you to modify
your proposed EP under Sec. 550.233(b)(2), you must submit the
modification(s) to the Regional Supervisor in the same manner as for a
new EP. You need submit only information related to the proposed
modification(s).
(b) Resubmitted EP. If the Regional Supervisor disapproves your EP
under Sec. 550.233(b)(3), you may resubmit the disapproved EP if there
is a change in the conditions that were the basis of its disapproval.
(c) BOEM review and timeframe. The Regional Supervisor will use the
performance standards in Sec. 550.202 to either approve, require you to
further modify, or disapprove your modified or resubmitted EP. The
Regional Supervisor will make a decision within 30 calendar days after
the Regional Supervisor deems your modified or resubmitted EP to be
submitted, or receives the last amendment to your modified or
resubmitted EP, whichever occurs later.

Sec. 550.235 If a State objects to the EP's coastal zone
consistency certification, what can I do?

If an affected State objects to the coastal zone consistency
certification accompanying your proposed EP within the timeframe
prescribed in Sec. 550.233(a) or Sec. 550.234(c), you may do one of
the following:
(a) Amend your EP. Amend your EP to accommodate the State's
objection and submit the amendment to the Regional Supervisor for
approval. The amendment needs to only address information related to the
State's objection.
(b) Appeal. Appeal the State's objection to the Secretary of
Commerce using the procedures in 15 CFR part 930, subpart H. The
Secretary of Commerce will either:
(1) Grant your appeal by finding, under section 307(c)(3)(B)(iii) of
the CZMA (16 U.S.C. 1456(c)(3)(B)(iii)), that each activity described in
detail in your EP is consistent with the objectives of the CZMA, or is
otherwise necessary in the interest of National security; or
(2) Deny your appeal, in which case you may amend your EP as
described in paragraph (a) of this section.

[[Page 384]]

Contents of Development and Production Plans (DPP) and Development
Operations Coordination Documents (DOCD)

Sec. 550.241 What must the DPP or DOCD include?

Your DPP or DOCD must include the following:
(a) Description, objectives, and schedule. A description, discussion
of the objectives, and tentative schedule (from start to completion) of
the development and production activities you propose to undertake.
Examples of development and production activities include:
(1) Development drilling;
(2) Well test flaring;
(3) Installation of production platforms, satellite structures,
subsea wellheads and manifolds, and lease term pipelines (see definition
at Sec. 550.105); and
(4) Installation of production facilities and conduct of production
operations.
(b) Location. The location and water depth of each of your proposed
wells and production facilities. Include a map showing the surface and
bottom-hole location and water depth of each proposed well, the surface
location of each production facility, and the locations of all
associated drilling unit and construction barge anchors.
(c) Drilling unit. A description of the drilling unit and associated
equipment you will use to conduct your proposed development drilling
activities. Include a brief description of its important safety and
pollution prevention features, and a table indicating the type and the
estimated maximum quantity of fuels and oil that will be stored on the
facility (see definition of ``facility (3)'' under Sec. 550.105).
(d) Production facilities. A description of the production
platforms, satellite structures, subsea wellheads and manifolds, lease
term pipelines (see definition at Sec. 550.105), production facilities,
umbilicals, and other facilities you will use to conduct your proposed
development and production activities. Include a brief description of
their important safety and pollution prevention features, and a table
indicating the type and the estimated maximum quantity of fuels and oil
that will be stored on the facility (see definition of ``facility (3)''
under Sec. 550.105).
(e) Service fee. You must include payment of the service fee listed
in Sec. 550.125.

Sec. 550.242 What information must accompany the DPP or DOCD?

The following information must accompany your DPP or DOCD.
(a) General information required by Sec. 550.243;
(b) G&G information required by Sec. 550.244;
(c) Hydrogen sulfide information required by Sec. 550.245;
(d) Mineral resource conservation information required by Sec.
550.246;
(e) Biological, physical, and socioeconomic information required by
Sec. 550.247;
(f) Solid and liquid wastes and discharges information and cooling
water intake information required by Sec. 550.248;
(g) Air emissions information required by Sec. 550.249;
(h) Oil and hazardous substance spills information required by Sec.
550.250;
(i) Alaska planning information required by Sec. 550.251;
(j) Environmental monitoring information required by Sec. 550.252;
(k) Lease stipulations information required by Sec. 550.253;
(l) Mitigation measures information required by Sec. 550.254;
(m) Decommissioning information required by Sec. 550.255;
(n) Related facilities and operations information required by Sec.
550.256;
(o) Support vessels and aircraft information required by Sec.
550.257;
(p) Onshore support facilities information required by Sec.
550.258;
(q) Sulphur operations information required by Sec. 550.259;
(r) Coastal zone management information required by Sec. 550.260;
(s) Environmental impact analysis information required by Sec.
550.261; and
(t) Administrative information required by Sec. 550.262.

[[Page 385]]

Sec. 550.243 What general information must accompany the DPP or DOCD?

The following general information must accompany your DPP or DOCD:
(a) Applications and permits. A listing, including filing or
approval status, of the Federal, State, and local application approvals
or permits you must obtain to carry out your proposed development and
production activities.
(b) Drilling fluids. A table showing the projected amount, discharge
rate, and chemical constituents for each type (i.e., water based, oil
based, synthetic based) of drilling fluid you plan to use to drill your
proposed development wells.
(c) Production. The following production information:
(1) Estimates of the average and peak rates of production for each
type of production and the life of the reservoir(s) you intend to
produce; and
(2) The chemical and physical characteristics of the produced oil
(see definition under 30 CFR 254.6) that you will handle or store at the
facilities you will use to conduct your proposed development and
production activities.
(d) Chemical products. A table showing the name and brief
description, quantities to be stored, storage method, and rates of usage
of the chemical products you will use to conduct your proposed
development and production activities. You need list only those chemical
products you will store or use in quantities greater than the amounts
defined as Reportable Quantities in 40 CFR part 302, or amounts
specified by the Regional Supervisor.
(e) New or unusual technology. A description and discussion of any
new or unusual technology (see definition under Sec. 550.200) you will
use to carry out your proposed development and production activities. In
the public information copies of your DPP or DOCD, you may exclude any
proprietary information from this description. In that case, include a
brief discussion of the general subject matter of the omitted
information. If you will not use any new or unusual technology to carry
out your proposed development and production activities, include a
statement so indicating.
(f) Bonds, oil spill financial responsibility, and well control
statements. Statements attesting that:
(1) The activities and facilities proposed in your DPP or DOCD are
or will be covered by an appropriate bond under 30 CFR part 556, subpart
I;
(2) You have demonstrated or will demonstrate oil spill financial
responsibility for facilities proposed in your DPP or DOCD, according to
30 CFR part 553; and
(3) You have or will have the financial capability to drill a relief
well and conduct other emergency well control operations.
(g) Suspensions of production or operations. A brief discussion of
any suspensions of production or suspensions of operations that you
anticipate may be necessary in the course of conducting your activities
under the DPP or DOCD.
(h) Blowout scenario. A scenario for a potential blowout of the
proposed well in your DPP or DOCD that you expect will have the highest
volume of liquid hydrocarbons. Include the estimated flow rate, total
volume, and maximum duration of the potential blowout. Also, discuss the
potential for the well to bridge over, the likelihood for surface
intervention to stop the blowout, the availability of a rig to drill a
relief well, and rig package constraints. Estimate the time it would
take to drill a relief well.
(i) Contact. The name, mailing address, (e-mail address if
available), and telephone number of the person with whom the Regional
Supervisor and the affected State(s) can communicate about your DPP or
DOCD.

Sec. 550.244 What geological and geophysical (G&G) information
must accompany the DPP or DOCD?

The following G&G information must accompany your DPP or DOCD:
(a) Geological description. A geological description of the
prospect(s).
(b) Structure contour maps. Current structure contour maps (depth-
based, expressed in feet subsea) showing depths of expected productive
formations and the locations of proposed wells.
(c) Two dimensional (2-D) or three-dimensional (3-D) seismic lines.
Copies of

[[Page 386]]

migrated and annotated 2-D or 3-D seismic lines (with depth scale)
intersecting at or near your proposed well locations. You are not
required to conduct both 2-D and 3-D seismic surveys if you choose to
conduct only one type of survey. If you have conducted both types of
surveys, the Regional Supervisor may instruct you to submit the results
of both surveys. You must interpret and display this information.
Provide this information as an enclosure to only one proprietary copy of
your DPP or DOCD.
(d) Geological cross-sections. Interpreted geological cross-sections
showing the depths of expected productive formations.
(e) Shallow hazards report. A shallow hazards report based on
information obtained from a high-resolution geophysical survey, or a
reference to such report if you have already submitted it to the
Regional Supervisor.
(f) Shallow hazards assessment. For each proposed well, an
assessment of any seafloor and subsurface geologic and manmade features
and conditions that may adversely affect your proposed drilling
operations.
(g) High resolution seismic lines. A copy of the high-resolution
survey line closest to each of your proposed well locations. Because of
its volume, provide this information as an enclosure to only one
proprietary copy of your DPP or DOCD. You are not required to provide
this information if the surface location of your proposed well has been
approved in a previously submitted EP, DPP, or DOCD.
(h) Stratigraphic column. A generalized biostratigraphic/
lithostratigraphic column from the surface to the total depth of each
proposed well.
(i) Time-versus-depth chart. A seismic travel time-versus-depth
chart based on the appropriate velocity analysis in the area of
interpretation and specifying the geodetic datum.
(j) Geochemical information. A copy of any geochemical reports you
used or generated.
(k) Future G&G activities. A brief description of the G&G
explorations and development G&G activities that you may conduct for
lease or unit purposes after your DPP or DOCD is approved.

Sec. 550.245 What hydrogen sulfide (H [bdi2]S) information
must accompany the DPP or DOCD?

The following H2S information, as applicable, must
accompany your DPP or DOCD:
(a) Concentration. The estimated concentration of any H2S
you might encounter or handle while you conduct your proposed
development and production activities.
(b) Classification. Under 30 CFR 250.490(c), a request that the
Regional Supervisor classify the area of your proposed development and
production activities as either H2S absent, H2S
present, or H2S unknown. Provide sufficient information to
justify your request.
(c) H 2S Contingency Plan. If you request that the
Regional Supervisor classify the area of your proposed development and
production activities as either H2S present or H2S
unknown, an H2S Contingency Plan prepared under 30 CFR
250.490(f), or a reference to an approved or submitted H2S
Contingency Plan that covers the proposed development and production
activities.
(d) Modeling report. (1) If you have determined or estimated that
the concentration of any H2S you may encounter or handle
while you conduct your development and production activities will be
greater than 500 parts per million (ppm), you must:
(i) Model a potential worst case H2S release from the
facilities you will use to conduct your proposed development and
production activities; and
(ii) Include a modeling report or modeling results, or a reference
to such report or results if you have already submitted it to the
Regional Supervisor.
(2) The analysis in the modeling report must be specific to the
particular site of your development and production activities, and must
consider any nearby human-occupied OCS facilities, shipping lanes,
fishery areas, and other points where humans may be subject to potential
exposure from an H2S release from your proposed activities.
(3) If any H2S emissions are projected to affect an
onshore location in concentrations greater than 10 ppm, the modeling
analysis must be consistent with the EPA's risk management plan

[[Page 387]]

methodologies outlined in 40 CFR part 68.

Sec. 550.246 What mineral resource conservation information
must accompany the DPP or DOCD?

The following mineral resource conservation information, as
applicable, must accompany your DPP or DOCD:
(a) Technology and reservoir engineering practices and procedures. A
description of the technology and reservoir engineering practices and
procedures you will use to increase the ultimate recovery of oil and gas
(e.g., secondary, tertiary, or other enhanced recovery practices). If
you will not use enhanced recovery practices initially, provide an
explanation of the methods you considered and the reasons why you are
not using them.
(b) Technology and recovery practices and procedures. A description
of the technology and recovery practices and procedures you will use to
ensure optimum recovery of oil and gas or sulphur.
(c) Reservoir development. A discussion of exploratory well results,
other reservoir data, proposed well spacing, completion methods, and
other relevant well plan information.

Sec. 550.247 What biological, physical, and socioeconomic information
must accompany the DPP or DOCD?

If you obtain the following information in developing your DPP or
DOCD, or if the Regional Supervisor requires you to obtain it, you must
include a report, or the information obtained, or a reference to such a
report or information if you have already submitted it to the Regional
Supervisor, as accompanying information:
(a) Biological environment reports. Site-specific information on
chemosynthetic communities, federally listed threatened or endangered
species, marine mammals protected under the MMPA, sensitive underwater
features, marine sanctuaries, critical habitat designated under the ESA,
or other areas of biological concern.
(b) Physical environment reports. Site-specific meteorological,
physical oceanographic, geotechnical reports, or archaeological reports
(if required under Sec. 550.194).
(c) Socioeconomic study reports. Socioeconomic information related
to your proposed development and production activities.

Sec. 550.248 What solid and liquid wastes and discharges information
and cooling water intake information must accompany the DPP or DOCD?

The following solid and liquid wastes and discharges information and
cooling water intake information must accompany your DPP or DOCD:
(a) Projected wastes. A table providing the name, brief description,
projected quantity, and composition of solid and liquid wastes (such as
spent drilling fluids, drill cuttings, trash, sanitary and domestic
wastes, produced waters, and chemical product wastes) likely to be
generated by your proposed development and production activities.
Describe:
(1) The methods you used for determining this information; and
(2) Your plans for treating, storing, and downhole disposal of these
wastes at your facility location(s).
(b) Projected ocean discharges. If any of your solid and liquid
wastes will be discharged overboard or are planned discharges from
manmade islands:
(1) A table showing the name, projected amount, and rate of
discharge for each waste type; and
(2) A description of the discharge method (such as shunting through
a downpipe, adding to a produced water stream, etc.) you will use.
(c) National Pollutant Discharge Elimination System (NPDES) permit.
(1) A discussion of how you will comply with the provisions of the
applicable general NPDES permit that covers your proposed development
and production activities; or
(2) A copy of your application for an individual NPDES permit.
Briefly describe the major discharges and methods you will use for
compliance.
(d) Modeling report. A modeling report or the modeling results (if
you modeled the discharges of your projected solid or liquid wastes in
developing your DPP or DOCD), or a reference to such report or results
if you have already submitted it to the Regional Supervisor.

[[Page 388]]

(e) Projected cooling water intake. A table for each cooling water
intake structure likely to be used by your proposed development and
production activities that includes a brief description of the cooling
water intake structure, daily water intake rate, water intake through-
screen velocity, percentage of water intake used for cooling water,
mitigation measures for reducing impingement and entrainment of aquatic
organisms, and biofouling prevention measures.

Sec. 550.249 What air emissions information must accompany the DPP or DOCD?

The following air emissions information, as applicable, must
accompany your DPP or DOCD:
(a) Projected emissions. Tables showing the projected emissions of
sulphur dioxide (SO2), particulate matter in the form of
PM10 and PM2.5 when applicable, nitrogen oxides
(NOX), carbon monoxide (CO), and volatile organic compounds
(VOC) that will be generated by your proposed development and production
activities.
(1) For each source on or associated with the facility you will use
to conduct your proposed development and production activities, you must
list:
(i) The projected peak hourly emissions;
(ii) The total annual emissions in tons per year;
(iii) Emissions over the duration of the proposed development and
production activities;
(iv) The frequency and duration of emissions; and
(v) The total of all emissions listed in paragraph (a)(1)(i) through
(iv) of this section.
(2) If your proposed production and development activities would
result in an increase in the emissions of an air pollutant from your
facility to an amount greater than the amount specified in your
previously approved DPP or DOCD, you must show the revised emission
rates for each source as well as the incremental change for each source.
(3) You must provide the basis for all calculations, including
engine size and rating, and applicable operational information.
(4) You must base the projected emissions on the maximum rated
capacity of the equipment and the maximum throughput of the facility you
will use to conduct your proposed development and production activities
under its physical and operational design.
(5) If the specific drilling unit has not yet been determined, you
must use the maximum emission estimates for the type of drilling unit
you will use.
(b) Emission reduction measures. A description of any proposed
emission reduction measures, including the affected source(s), the
emission reduction control technologies or procedures, the quantity of
reductions to be achieved, and any monitoring system you propose to use
to measure emissions.
(c) Processes, equipment, fuels, and combustibles. A description of
processes, processing equipment, combustion equipment, fuels, and
storage units. You must include the frequency, duration, and maximum
burn rate of any flaring activity.
(d) Distance to shore. Identification of the distance of the site of
your proposed development and production activities from the mean high
water mark (mean higher high water mark on the Pacific coast) of the
adjacent State.
(e) Non-exempt facilities. A description of how you will comply with
Sec. 550.303 when the projected emissions of SO2, PM,
NOX, CO, or VOC that will be generated by your proposed
development and production activities are greater than the respective
emission exemption amounts ``E'' calculated using the formulas in Sec.
550.303(d). When BOEM requires air quality modeling, you must use the
guidelines in appendix W of 40 CFR part 51 with a model approved by the
Director. Submit the best available meteorological information and data
consistent with the model(s) used.
(f) Modeling report. A modeling report or the modeling results (if
Sec. 550.303 requires you to use an approved air quality model to model
projected air emissions in developing your DPP or DOCD), or a reference
to such report or results if you have already submitted it to the
Regional Supervisor.

[[Page 389]]

Sec. 550.250 What oil and hazardous substance spills information
must accompany the DPP or DOCD?

The following information regarding potential spills of oil (see
definition under 30 CFR 254.6) and hazardous substances (see definition
under 40 CFR part 116), as applicable, must accompany your DPP or DOCD:
(a) Oil spill response planning. The material required under
paragraph (a)(1) or (a)(2) of this section:
(1) An Oil Spill Response Plan (OSRP) for the facilities you will
use to conduct your proposed development and production activities
prepared according to the requirements of 30 CFR part 254, subpart B; or
(2) Reference to your approved regional OSRP (see 30 CFR 254.3) to
include:
(i) A discussion of your regional OSRP;
(ii) The location of your primary oil spill equipment base and
staging area;
(iii) The name(s) of your oil spill removal organization(s) for both
equipment and personnel;
(iv) The calculated volume of your worst case discharge scenario
(see 30 CFR 254.26(a)), and a comparison of the appropriate worst case
discharge scenario in your approved regional OSRP with the worst case
discharge scenario that could result from your proposed development and
production activities; and
(v) A description of the worst case oil spill scenario that could
result from your proposed development and production activities (see 30
CFR 254.26(b), (c), (d), and (e)).
(b) Modeling report. If you model a potential oil or hazardous
substance spill in developing your DPP or DOCD, a modeling report or the
modeling results, or a reference to such report or results if you have
already submitted it to the Regional Supervisor.

Sec. 550.251 If I propose activities in the Alaska OCS Region,
what planning information must accompany the DPP?

If you propose development and production activities in the Alaska
OCS Region, the following planning information must accompany your DPP:
(a) Emergency plans. A description of your emergency plans to
respond to a blowout, loss or disablement of a drilling unit, and loss
of or damage to support craft; and
(b) Critical operations and curtailment procedures. Critical
operations and curtailment procedures for your development and
production activities. The procedures must identify ice conditions,
weather, and other constraints under which the development and
production activities will either be curtailed or not proceed.

Sec. 550.252 What environmental monitoring information
must accompany the DPP or DOCD?

The following environmental monitoring information, as applicable,
must accompany your DPP or DOCD:
(a) Monitoring systems. A description of any existing and planned
monitoring systems that are measuring, or will measure, environmental
conditions or will provide project-specific data or information on the
impacts of your development and production activities.
(b) Incidental takes. If there is reason to believe that protected
species may be incidentally taken by planned development and production
activities, you must describe how you will monitor for incidental take
of:
(1) Threatened and endangered species listed under the ESA; and
(2) Marine mammals, as appropriate, if you have not already received
authorization for incidental take of marine mammals as may be necessary
under the MMPA.
(c) Flower Garden Banks National Marine Sanctuary (FGBNMS). If you
propose to conduct development and production activities within the
protective zones of the FGBNMS, a description of your provisions for
monitoring the impacts of oil spill on the environmentally sensitive
resources of the FGBNMS.

Sec. 550.253 What lease stipulations information
must accompany the DPP or DOCD?

A description of the measures you took, or will take, to satisfy the
conditions of lease stipulations related to

[[Page 390]]

your proposed development and production activities must accompany your
DPP or DOCD.

Sec. 550.254 What mitigation measures information
must accompany the DPP or DOCD?

(a) If you propose to use any measures beyond those required by the
regulations in this part to minimize or mitigate environmental impacts
from your proposed development and production activities, a description
of the measures you will use must accompany your DPP or DOCD.
(b) If there is reason to believe that protected species may be
incidentally taken by planned development and production activities, you
must include mitigation measures designed to avoid or minimize that
incidental take of:
(1) Threatened and endangered species listed under the ESA; and
(2) Marine mammals, as appropriate, if you have not already received
authorization for incidental take as may be necessary under the MMPA.

Sec. 550.255 What decommissioning information must accompany the DPP or DOCD?

A brief description of how you intend to decommission your wells,
platforms, pipelines, and other facilities, and clear your site(s) must
accompany your DPP or DOCD.

Sec. 550.256 What related facilities and operations information
must accompany the DPP or DOCD?

The following information regarding facilities and operations
directly related to your proposed development and production activities
must accompany your DPP or DOCD.
(a) OCS facilities and operations. A description and location of any
of the following that directly relate to your proposed development and
production activities:
(1) Drilling units;
(2) Production platforms;
(3) Right-of-way pipelines (including those that transport chemical
products and produced water); and
(4) Other facilities and operations located on the OCS (regardless
of ownership).
(b) Transportation system. A discussion of the transportation system
that you will use to transport your production to shore, including:
(1) Routes of any new pipelines;
(2) Information concerning barges and shuttle tankers, including the
storage capacity of the transport vessel(s), and the number of transfers
that will take place per year;
(3) Information concerning any intermediate storage or processing
facilities;
(4) An estimate of the quantities of oil, gas, or sulphur to be
transported from your production facilities; and
(5) A description and location of the primary onshore terminal.

Sec. 550.257 What information on the support vessels, offshore vehicles,
and aircraft you will use must accompany the DPP or DOCD?

The following information on the support vessels, offshore vehicles,
and aircraft you will use must accompany your DPP or DOCD:
(a) General. A description of the crew boats, supply boats, anchor
handling vessels, tug boats, barges, ice management vessels, other
vessels, offshore vehicles, and aircraft you will use to support your
development and production activities. The description of vessels and
offshore vehicles must estimate the storage capacity of their fuel tanks
and the frequency of their visits to the facilities you will use to
conduct your proposed development and production activities.
(b) Air emissions. A table showing the source, composition,
frequency, and duration of the air emissions likely to be generated by
the support vessels, offshore vehicles, and aircraft you will use that
will operate within 25 miles of the facilities you will use to conduct
your proposed development and production activities.
(c) Drilling fluids and chemical products transportation. A
description of the transportation method and quantities of drilling
fluids and chemical products (see Sec. 550.243(b) and (d)) you will
transport from the onshore support facilities you will use to the
facilities you will use to conduct your proposed development and
production activities.
(d) Solid and liquid wastes transportation. A description of the
transportation method and a brief description

[[Page 391]]

of the composition, quantities, and destination(s) of solid and liquid
wastes (see Sec. 550.248(a)) you will transport from the facilities you
will use to conduct your proposed development and production activities.
(e) Vicinity map. A map showing the location of your proposed
development and production activities relative to the shoreline. The map
must depict the primary route(s) the support vessels and aircraft will
use when traveling between the onshore support facilities you will use
and the facilities you will use to conduct your proposed development and
production activities.

Sec. 550.258 What information on the onshore support facilities you will use
must accompany the DPP or DOCD?

The following information on the onshore support facilities you will
use must accompany your DPP or DOCD:
(a) General. A description of the onshore facilities you will use to
provide supply and service support for your proposed development and
production activities (e.g., service bases and mud company docks).
(1) Indicate whether the onshore support facilities are existing, to
be constructed, or to be expanded; and
(2) For DPPs only, provide a timetable for acquiring lands
(including rights-of-way and easements) and constructing or expanding
any of the onshore support facilities.
(b) Air emissions. A description of the source, composition,
frequency, and duration of the air emissions (attributable to your
proposed development and production activities) likely to be generated
by the onshore support facilities you will use.
(c) Unusual solid and liquid wastes. A description of the quantity,
composition, and method of disposal of any unusual solid and liquid
wastes (attributable to your proposed development and production
activities) likely to be generated by the onshore support facilities you
will use. Unusual wastes are those wastes not specifically addressed in
the relevant National Pollution Discharge Elimination System (NPDES)
permit.
(d) Waste disposal. A description of the onshore facilities you will
use to store and dispose of solid and liquid wastes generated by your
proposed development and production activities (see Sec. 550.248(a))
and the types and quantities of such wastes.

Sec. 550.259 What sulphur operations information
must accompany the DPP or DOCD?

If you are proposing to conduct sulphur development and production
activities, the following information must accompany your DPP or DOCD:
(a) Bleedwater. A discussion of the bleedwater that will be
generated by your proposed sulphur activities, including the measures
you will take to mitigate the potential toxic or thermal impacts on the
environment caused by the discharge of bleedwater.
(b) Subsidence. An estimate of the degree of subsidence expected at
various stages of your sulphur development and production activities,
and a description of the measures you will take to mitigate the effects
of subsidence on existing or potential oil and gas production,
production platforms, and production facilities, and to protect the
environment.

Sec. 550.260 What Coastal Zone Management Act (CZMA) information
must accompany the DPP or DOCD?

The following CZMA information must accompany your DPP or DOCD:
(a) Consistency certification. A copy of your consistency
certification under section 307(c)(3)(B) of the CZMA (16 U.S.C.
1456(c)(3)(B)) and 15 CFR 930.76(c) stating that the proposed
development and production activities described in detail in this DPP or
DOCD comply with (name of State(s)) approved coastal management
program(s) and will be conducted in a manner that is consistent with
such program(s); and
(b) Other information. ``Information'' as required by 15 CFR
930.76(a) and 15 CFR 930.58(a)(2)) and ``Analysis'' as required by 15
CFR 930.58(a)(3).

Sec. 550.261 What environmental impact analysis (EIA) information
must accompany the DPP or DOCD?

The following EIA information must accompany your DPP or DOCD:
(a) General requirements. Your EIA must:

[[Page 392]]

(1) Assess the potential environmental impacts of your proposed
development and production activities;
(2) Be project specific; and
(3) Be as detailed as necessary to assist the Regional Supervisor in
complying with the NEPA of 1969 (42 U.S.C. 4321 et seq.) and other
relevant Federal laws such as the ESA and the MMPA.
(b) Resources, conditions, and activities. Your EIA must describe
those resources, conditions, and activities listed below that could be
affected by your proposed development and production activities, or that
could affect the construction and operation of facilities or structures
or the activities proposed in your DPP or DOCD.
(1) Meteorology, oceanography, geology, and shallow geological or
manmade hazards;
(2) Air and water quality;
(3) Benthic communities, marine mammals, sea turtles, coastal and
marine birds, fish and shellfish, and plant life;
(4) Threatened or endangered species and their critical habitat;
(5) Sensitive biological resources or habitats such as essential
fish habitat, refuges, preserves, special management areas identified in
coastal management programs, sanctuaries, rookeries, and calving
grounds;
(6) Archaeological resources;
(7) Socioeconomic resources (including the approximate number,
timing, and duration of employment of persons engaged in onshore support
and construction activities), population (including the approximate
number of people and families added to local onshore areas), existing
offshore and onshore infrastructure (including major sources of
supplies, services, energy, and water), types of contractors or vendors
that may place a demand on local goods and services, land use,
subsistence resources and harvest practices, recreation, recreational
and commercial fishing (including seasons, location, and type), minority
and lower income groups, and CZMA programs;
(8) Coastal and marine uses such as military activities, shipping,
and mineral exploration or development; and
(9) Other resources, conditions, and activities identified by the
Regional Supervisor.
(c) Environmental impacts. Your EIA must:
(1) Analyze the potential direct and indirect impacts (including
those from accidents, cooling water intake structures, and those
identified in relevant ESA biological opinions such as, but not limited
to, those from noise, vessel collisions, and marine trash and debris)
that your proposed development and production activities will have on
the identified resources, conditions, and activities;
(2) Describe the type, severity, and duration of these potential
impacts and their biological, physical, and other consequences and
implications;
(3) Describe potential measures to minimize or mitigate these
potential impacts;
(4) Describe any alternatives to your proposed development and
production activities that you considered while developing your DPP or
DOCD, and compare the potential environmental impacts; and
(5) Summarize the information you incorporate by reference.
(d) Consultation. Your EIA must include a list of agencies and
persons with whom you consulted, or with whom you will be consulting,
regarding potential impacts associated with your proposed development
and production activities.
(e) References cited. Your EIA must include a list of the references
that you cite in the EIA.

Sec. 550.262 What administrative information must accompany the DPP or DOCD?

The following administrative information must accompany your DPP or
DOCD:
(a) Exempted information description (public information copies
only). A description of the general subject matter of the proprietary
information that is included in the proprietary copies of your DPP or
DOCD or its accompanying information.
(b) Bibliography. (1) If you reference a previously submitted EP,
DPP, DOCD, study report, survey report, or other material in your DPP or
DOCD or its accompanying information, a list of the referenced material;
and

[[Page 393]]

(2) The location(s) where the Regional Supervisor can inspect the
cited referenced material if you have not submitted it.

Review and Decision Process for the DPP or DOCD

Sec. 550.266 After receiving the DPP or DOCD, what will BOEM do?

(a) Determine whether deemed submitted. Within 25 working days after
receiving your proposed DPP or DOCD and its accompanying information,
the Regional Supervisor will deem your DPP or DOCD submitted if:
(1) The submitted information, including the information that must
accompany the DPP or DOCD (refer to the list in Sec. 550.242), fulfills
requirements and is sufficiently accurate;
(2) You have provided all needed additional information (see Sec.
550.201(b)); and
(3) You have provided the required number of copies (see Sec.
550.206(a)).
(b) Identify problems and deficiencies. If the Regional Supervisor
determines that you have not met one or more of the conditions in
paragraph (a) of this section, the Regional Supervisor will notify you
of the problem or deficiency within 25 working days after the Regional
Supervisor receives your DPP or DOCD and its accompanying information.
The Regional Supervisor will not deem your DPP or DOCD submitted until
you have corrected all problems or deficiencies identified in the
notice.
(c) Deemed submitted notification. The Regional Supervisor will
notify you when your DPP or DOCD is deemed submitted.

Sec. 550.267 What actions will BOEM take after the DPP or DOCD
is deemed submitted?

(a) State, local government, CZMA consistency, and other reviews.
Within 2 working days after the Regional Supervisor deems your DPP or
DOCD submitted under Sec. 550.266, the Regional Supervisor will use
receipted mail or alternative method to send a public information copy
of the DPP or DOCD and its accompanying information to the following:
(1) The Governor of each affected State. The Governor has 60
calendar days after receiving your deemed-submitted DPP or DOCD to
submit comments and recommendations. The Regional Supervisor will not
consider comments and recommendations received after the deadline.
(2) The executive of any affected local government who requests a
copy. The executive of any affected local government has 60 calendar
days after receipt of your deemed-submitted DPP or DOCD to submit
comments and recommendations. The Regional Supervisor will not consider
comments and recommendations received after the deadline. The executive
of any affected local government must forward all comments and
recommendations to the respective Governor before submitting them to the
Regional Supervisor.
(3) The CZMA agency of each affected State. The CZMA consistency
review period under section 307(c)(3)(B)(ii) of the CZMA (16
U.S.C.1456(c)(3)(B)(ii)) and 15 CFR 930.78 begins when the States CZMA
agency receives a copy of your deemed-submitted DPP or DOCD, consistency
certification, and required necessary data/information (see 15 CFR
930.77(a)(1)).
(b) General public. Within 2 working days after the Regional
Supervisor deems your DPP or DOCD submitted under Sec. 550.266, the
Regional Supervisor will make a public information copy of the DPP or
DOCD and its accompanying information available for review to any
appropriate interstate regional entity and the public at the appropriate
BOEM Regional Public Information Office. Any interested Federal agency
or person may submit comments and recommendations to the Regional
Supervisor. Comments and recommendations must be received by the
Regional Supervisor within 60 calendar days after the DPP or DOCD
including its accompanying information is made available.
(c) BOEM compliance review. The Regional Supervisor will review the
development and production activities in your proposed DPP or DOCD to
ensure that they conform to the performance standards in Sec. 550.202.
(d) Amendments. During the review of your proposed DPP or DOCD, the
Regional Supervisor may require you, or you may elect, to change your
DPP or DOCD. If you elect to amend your DPP

[[Page 394]]

or DOCD, the Regional Supervisor may determine that your DPP or DOCD, as
amended, is subject to the requirements of Sec. 550.266.

Sec. 550.268 How does BOEM respond to recommendations?

(a) Governor. The Regional Supervisor will accept those
recommendations from the Governor that provide a reasonable balance
between the National interest and the well-being of the citizens of each
affected State. The Regional Supervisor will explain in writing to the
Governor the reasons for rejecting any of his or her recommendations.
(b) Local governments and the public. The Regional Supervisor may
accept recommendations from the executive of any affected local
government or the public.
(c) Availability. The Regional Supervisor will make all comments and
recommendations available to the public upon request.

Sec. 550.269 How will BOEM evaluate the environmental impacts
of the DPP or DOCD?

The Regional Supervisor will evaluate the environmental impacts of
the activities described in your proposed DPP or DOCD and prepare
environmental documentation under the National Environmental Policy Act
(NEPA) (42 U.S.C.4321 et seq.) and the implementing regulations (40 CFR
parts 1500 through 1508).
(a) Environmental impact statement (EIS) declaration. At least once
in each OCS planning area (other than the Western and Central GOM
Planning Areas), the Director will declare that the approval of a
proposed DPP is a major Federal action, and BOEM will prepare an EIS.
(b) Leases or units in the vicinity. Before or immediately after the
Director determines that preparation of an EIS is required, the Regional
Supervisor may require lessees and operators of leases or units in the
vicinity of the proposed development and production activities for which
DPPs have not been approved to submit information about preliminary
plans for their leases or units.
(c) Draft EIS. The Regional Supervisor will send copies of the draft
EIS to the Governor of each affected State and to the executive of each
affected local government who requests a copy. Additionally, when BOEM
prepares a DPP EIS, and the Federally-approved CZMA program for an
affected State requires a DPP NEPA document for use in determining
consistency, the Regional Supervisor will forward a copy of the draft
EIS to the State's CZMA agency. The Regional Supervisor will also make
copies of the draft EIS available to any appropriate Federal agency,
interstate regional entity, and the public.

Sec. 550.270 What decisions will BOEM make on the DPP or DOCD
and within what timeframe?

(a) Timeframe. The Regional Supervisor will act on your deemed-
submitted DPP or DOCD as follows:
(1) The Regional Supervisor will make a decision within 60 calendar
days after the latest of the day that:
(i) The comment period provided in Sec. 550.267(a)(1), (a)(2), and
(b) closes;
(ii) The final EIS for a DPP is released or adopted; or
(iii) The last amendment to your proposed DOCD is received by the
Regional Supervisor.
(2) Notwithstanding paragraph (a)(1) of this section, BOEM will not
approve your DPP or DOCD until either:
(i) All affected States with approved CZMA programs concur, or have
been conclusively presumed to concur, with your DPP or DOCD consistency
certification under section 307(c)(3)(B)(i) and (ii) of the CZMA (16
U.S.C. 1456(c)(3)(B)(i) and (ii)); or
(ii) The Secretary of Commerce has made a finding authorized by
section 307(c)(3)(B)(iii) of the CZMA (16 U.S.C. 1456(c)(3)(B)(iii))
that each activity described in the DPP or DOCD is consistent with the
objectives of the CZMA, or is otherwise necessary in the interest of
National security.
(b) BOEM decision. By the deadline in paragraph (a) of this section,
the Regional Supervisor will take one of the following actions:

[[Page 395]]

------------------------------------------------------------------------
The regional
supervisor will . . . If . . . And then . . .
------------------------------------------------------------------------
(1) Approve your DPP It complies with all The Regional Supervisor
or DOCD, applicable will notify you in
requirements, writing of the decision
and may require you to
meet certain conditions,
including those to
provide monitoring
information.
(2) Require you to It fails to make The Regional Supervisor
modify your proposed adequate provisions will notify you in
DPP or DOCD, for safety, writing of the decision
environmental and describe the
protection, or modifications you must
conservation of make to your proposed
natural resources or DPP or DOCD to ensure it
otherwise does not complies with all
comply with the applicable requirements.
lease, the Act, the
regulations
prescribed under the
Act, or other
Federal laws,
(3) Disapprove your Any of the reasons in (i) The Regional
DPP or DOCD, Sec. 550.271 Supervisor will notify
apply, you in writing of the
decision and describe
the reason(s) for
disapproving your DPP or
DOCD; and
(ii) BOEM may cancel your
lease and compensate you
under 43 U.S.C.
1351(h)(2)(C) and the
implementing regulations
in Sec. Sec. 550.183
through 550.185 and 30
CFR 556.77.
------------------------------------------------------------------------

Sec. 550.271 For what reasons will BOEM disapprove the DPP or DOCD?

The Regional Supervisor will disapprove your proposed DPP or DOCD if
one of the four reasons in this section applies:
(a) Non-compliance. The Regional Supervisor determines that you have
failed to demonstrate that you can comply with the requirements of the
Outer Continental Shelf Lands Act, as amended (Act), implementing
regulations, or other applicable Federal laws.
(b) No consistency concurrence. (1) An affected State has not yet
issued a final decision on your coastal zone consistency certification
(see 15 CFR 930.78(a)); or
(2) An affected State objects to your coastal zone consistency
certification, and the Secretary of Commerce, under section
307(c)(3)(B)(iii) of the CZMA (16 U.S.C. 1456(c)(3)(B)(iii)), has not
found that each activity described in the DPP or DOCD is consistent with
the objectives of the CZMA or is otherwise necessary in the interest of
National security.
(3) If the Regional Supervisor disapproved your DPP or DOCD for the
sole reason that an affected State either has not yet issued a final
decision on, or has objected to, your coastal zone consistency
certification (see paragraphs (b)(1) and (2) in this section), the
Regional Supervisor will approve your DPP or DOCD upon receipt of
concurrence by the affected State, at the time concurrence of the
affected State is conclusively presumed, or when the Secretary of
Commerce makes a finding authorized by section 307(c)(3)(B)(iii) of the
CZMA (16 U.S.C. 1456(c)(3)(B)(iii)) that each activity described in your
DPP or DOCD is consistent with the objectives of the CZMA, or is
otherwise necessary in the interest of National security. In that event,
you do not need to resubmit your DPP or DOCD for approval under Sec.
550.273(b).
(c) National security or defense conflicts. Your proposed activities
would threaten National security or defense.
(d) Exceptional circumstances. The Regional Supervisor determines
because of exceptional geological conditions, exceptional resource
values in the marine or coastal environment, or other exceptional
circumstances that all of the following apply:
(1) Implementing your DPP or DOCD would cause serious harm or damage
to life (including fish and other aquatic life), property, any mineral
deposits (in areas leased or not leased), the National security or
defense, or the marine, coastal, or human environment;
(2) The threat of harm or damage will not disappear or decrease to
an acceptable extent within a reasonable period of time; and
(3) The advantages of disapproving your DPP or DOCD outweigh the
advantages of development and production.

Sec. 550.272 If a State objects to the DPP's or DOCD's coastal zone
consistency certification, what can I do?

If an affected State objects to the coastal zone consistency
certification

[[Page 396]]

accompanying your proposed or disapproved DPP or DOCD, you may do one of
the following:
(a) Amend or resubmit your DPP or DOCD. Amend or resubmit your DPP
or DOCD to accommodate the State's objection and submit the amendment or
resubmittal to the Regional Supervisor for approval. The amendment or
resubmittal needs to only address information related to the State's
objections.
(b) Appeal. Appeal the State's objection to the Secretary of
Commerce using the procedures in 15 CFR part 930, subpart H. The
Secretary of Commerce will either:
(1) Grant your appeal by finding under section 307(c)(3)(B)(iii) of
the CZMA (16 U.S.C.1456(c)(3)(B)(iii)) that each activity described in
detail in your DPP or DOCD is consistent with the objectives of the
CZMA, or is otherwise necessary in the interest of National security; or
(2) Deny your appeal, in which case you may amend or resubmit your
DPP or DOCD, as described in paragraph (a) of this section.
(c) Withdraw your DPP or DOCD. Withdraw your DPP or DOCD if you
decide not to conduct your proposed development and production
activities.

Sec. 550.273 How do I submit a modified DPP or DOCD or resubmit
a disapproved DPP or DOCD?

(a) Modified DPP or DOCD. If the Regional Supervisor requires you to
modify your proposed DPP or DOCD under Sec. 550.270(b)(2), you must
submit the modification(s) to the Regional Supervisor in the same manner
as for a new DPP or DOCD. You need submit only information related to
the proposed modification(s).
(b) Resubmitted DPP or DOCD. If the Regional Supervisor disapproves
your DPP or DOCD under Sec. 550.270(b)(3), and except as provided in
Sec. 550.271(b)(3), you may resubmit the disapproved DPP or DOCD if
there is a change in the conditions that were the basis of its
disapproval.
(c) BOEM review and timeframe. The Regional Supervisor will use the
performance standards in Sec. 550.202 to either approve, require you to
further modify, or disapprove your modified or resubmitted DPP or DOCD.
The Regional Supervisor will make a decision within 60 calendar days
after the Regional Supervisor deems your modified or resubmitted DPP or
DOCD to be submitted, or receives the last amendment to your modified or
resubmitted DPP or DOCD, whichever occurs later.

Post-Approval Requirements for the EP, DPP, and DOCD

Sec. 550.280 How must I conduct activities under the approved EP,
DPP, or DOCD?

(a) Compliance. You must conduct all of your lease and unit
activities according to your approved EP, DPP, or DOCD and any approval
conditions. If you fail to comply with your approved EP, DPP, or DOCD:
(1) You may be subject to BOEM enforcement action, including civil
penalties; and
(2) The lease(s) involved in your EP, DPP, or DOCD may be forfeited
or cancelled under 43 U.S.C. 1334(c) or (d). If this happens, you will
not be entitled to compensation under Sec. 550.185(b) and 30 CFR
556.77.
(b) Emergencies. Nothing in this subpart or in your approved EP,
DPP, or DOCD relieves you of, or limits your responsibility to take
appropriate measures to meet emergency situations. In an emergency
situation, the Regional Supervisor may approve or require departures
from your approved EP, DPP, or DOCD.

Sec. 550.281 What must I do to conduct activities under the approved EP,
DPP, or DOCD?

(a) Approvals and permits. Before you conduct activities under your
approved EP, DPP, or DOCD you must obtain the following approvals and or
permits, as applicable, from the District Manager or BSEE Regional
Supervisor:
(1) Approval of applications for permits to drill (APDs) (see 30 CFR
250.410);
(2) Approval of production safety systems (see 30 CFR 250.800);
(3) Approval of new platforms and other structures (or major
modifications to platforms and other structures) (see 30 CFR 250.905);

[[Page 397]]

(4) Approval of applications to install lease term pipelines (see 30
CFR 250.1007); and
(5) Other permits, as required by applicable law.
(b) Conformance. The activities proposed in these applications and
permits must conform to the activities described in detail in your
approved EP, DPP, or DOCD.
(c) Separate State CZMA consistency review. APDs, and other
applications for licenses, approvals, or permits to conduct activities
under your approved EP, DPP, or DOCD including those identified in
paragraph (a) of this section, are not subject to separate State CZMA
consistency review.
(d) Approval restrictions for permits for activities conducted under
EPs. The Regional Supervisor will not approve any APDs or other
applications for licenses, approvals, or permits under your approved EP
until either:
(1) All affected States with approved coastal zone management
programs concur, or are conclusively presumed to concur, with the
coastal zone consistency certification accompanying your EP under
section 307(c)(3)(B)(i) and (ii) of the CZMA (16 U.S.C. 1456(c)(3)(B)(i)
and (ii)); or
(2) The Secretary of Commerce finds, under section 307(c)(3)(B)(iii)
of the CZMA (16 U.S.C.1456(c)(3)(B)(iii)) that each activity covered by
the EP is consistent with the objectives of the CZMA or is otherwise
necessary in the interest of National security;
(3) If an affected State objects to the coastal zone consistency
certification accompanying your approved EP after BOEM has approved your
EP, you may either:
(i) Revise your EP to accommodate the State's objection and submit
the revision to the Regional Supervisor for approval; or
(ii) Appeal the State's objection to the Secretary of Commerce using
the procedures in 15 CFR part 930, subpart H. The Secretary of Commerce
will either:
(A) Grant your appeal by making the finding described in paragraph
(d)(2) of this section; or
(B) Deny your appeal, in which case you may revise your EP as
described in paragraph (d)(3)(i) of this section.

Sec. 550.282 Do I have to conduct post-approval monitoring?

After approving your EP, DPP, or DOCD, the Regional Supervisor may
direct you to conduct monitoring programs, including monitoring in
accordance with the ESA and the MMPA. You must retain copies of all
monitoring data obtained or derived from your monitoring programs and
make them available to the BOEM upon request. The Regional Supervisor
may require you to:
(a) Monitoring plans. Submit monitoring plans for approval before
you begin the work; and
(b) Monitoring reports. Prepare and submit reports that summarize
and analyze data and information obtained or derived from your
monitoring programs. The Regional Supervisor will specify requirements
for preparing and submitting these reports.

Sec. 550.283 When must I revise or supplement the approved EP,
DPP, or DOCD?

(a) Revised OCS plans. You must revise your approved EP, DPP, or
DOCD when you propose to:
(1) Change the type of drilling rig (e.g., jack-up, platform rig,
barge, submersible, semisubmersible, or drillship), production facility
(e.g., caisson, fixed platform with piles, tension leg platform), or
transportation mode (e.g., pipeline, barge);
(2) Change the surface location of a well or production platform by
a distance more than that specified by the Regional Supervisor;
(3) Change the type of production or significantly increase the
volume of production or storage capacity;
(4) Increase the emissions of an air pollutant to an amount that
exceeds the amount specified in your approved EP, DPP, or DOCD;
(5) Significantly increase the amount of solid or liquid wastes to
be handled or discharged;
(6) Request a new H2S area classification, or increase
the concentration of H2S to a concentration greater than that
specified by the Regional Supervisor;
(7) Change the location of your onshore support base either from one

[[Page 398]]

State to another or to a new base or a base requiring expansion; or
(8) Change any other activity specified by the Regional Supervisor.
(b) Supplemental OCS plans. You must supplement your approved EP,
DPP, or DOCD when you propose to conduct activities on your lease(s) or
unit that require approval of a license or permit which is not described
in your approved EP, DPP, or DOCD. These types of changes are called
supplemental OCS plans.

Sec. 550.284 How will BOEM require revisions to the approved EP,
DPP, or DOCD?

(a) Periodic review. The Regional Supervisor will periodically
review the activities you conduct under your approved EP, DPP, or DOCD
and may require you to submit updated information on your activities.
The frequency and extent of this review will be based on the
significance of any changes in available information and onshore or
offshore conditions affecting, or affected by, the activities in your
approved EP, DPP, or DOCD.
(b) Results of review. The Regional Supervisor may require you to
revise your approved EP, DPP, or DOCD based on this review. In such
cases, the Regional Supervisor will inform you of the reasons for the
decision.

Sec. 550.285 How do I submit revised and supplemental EPs, DPPs, and DOCDs?

(a) Submittal. You must submit to the Regional Supervisor any
revisions and supplements to approved EPs, DPPs, or DOCDs for approval,
whether you initiate them or the Regional Supervisor orders them.
(b) Information. Revised and supplemental EPs, DPPs, and DOCDs need
include only information related to or affected by the proposed changes,
including information on changes in expected environmental impacts.
(c) Procedures. All supplemental EPs, DPPs, and DOCDs, and those
revised EPs, DPPs, and DOCDs that the Regional Supervisor determines are
likely to result in a significant change in the impacts previously
identified and evaluated, are subject to all of the procedures under
Sec. Sec. 550.231 through 550.235 for EPs and Sec. Sec. 550.266
through 550.273 for DPPs and DOCDs.

Sec. Sec. 550.286-550.295 [Reserved]

Conservation Information Documents (CID)

Sec. 550.296 When and how must I submit a CID or a revision to a CID?

(a) You must submit one original and two copies of a CID to the
appropriate OCS Region at the same time you first submit your DOCD or
DPP for any development of a lease or leases located in water depths
greater than 400 meters (1,312 feet). You must also submit a CID for a
Supplemental DOCD or DPP when requested by the Regional Supervisor. The
submission of your CID must be accompanied by payment of the service fee
listed in Sec. 550.125.
(b) If you decide not to develop a reservoir you committed to
develop in your CID, you must submit one original and two copies of a
revision to the CID to the appropriate OCS Region. The revision to the
CID must be submitted within 14 calendar days after making your decision
not to develop the reservoir and before the reservoir is bypassed. The
Regional Supervisor will approve or disapprove any such revision to the
original CID. If the Regional Supervisor disapproves the revision, you
must develop the reservoir as described in the original CID.

Sec. 550.297 What information must a CID contain?

(a) You must base the CID on wells drilled before your CID submittal
that define the extent of the reservoirs. You must notify BOEM of any
well that is drilled to total depth during the CID evaluation period and
you may be required to update your CID.
(b) You must include all of the following information if available.
Information must be provided for each hydrocarbon-bearing reservoir that
is penetrated by a well that would meet the producibility requirements
of Sec. 550.115 or Sec. 550.116:
(1) General discussion of the overall development of the reservoir;
(2) Summary spreadsheets of well log data and reservoir parameters
(i.e., sand tops and bases, fluid contacts, net

[[Page 399]]

pay, porosity, water saturations, pressures, formation volume factor);
(3) Appropriate well logs, including digital well log (i.e., gamma
ray, resistivity, neutron, density, sonic, caliper curves) curves in an
acceptable digital format;
(4) Sidewall core/whole core and pressure-volume-temperature
analysis;
(5) Structure maps, with the existing and proposed penetration
points and subsea depths for all wells penetrating the reservoirs, fluid
contacts (or the lowest or highest known levels in the absence of actual
contacts), reservoir boundaries, and the scale of the map;
(6) Interpreted structural cross sections and corresponding
interpreted seismic lines or block diagrams, as necessary, that include
all current wellbores and planned wellbores on the leases or units to be
developed, the reservoir boundaries, fluid contacts, depth scale,
stratigraphic positions, and relative biostratigraphic ages;
(7) Isopach maps of each reservoir showing the net feet of pay for
each well within the reservoir identified at the penetration point,
along with the well name, labeled contours, and scale;
(8) Estimates of original oil and gas in-place and anticipated
recoverable oil and gas reserves, all reservoir parameters, and risk
factors and assumptions;
(9) Plat map at the same scale as the structure maps with existing
and proposed well paths, as well as existing and proposed penetrations;
(10) Wellbore schematics indicating proposed perforations;
(11) Proposed wellbore utility chart showing all existing and
proposed wells, with proposed completion intervals indicated for each
borehole;
(12) Appropriate pressure data, specified by date, and whether
estimated or measured;
(13) Description of reservoir development strategies;
(14) Description of the enhanced recovery practices you will use or,
if you do not plan to use such practices, an explanation of the methods
you considered and reasons you do not intend to use them;
(15) For each reservoir you do not intend to develop:
(i) A statement explaining the reason(s) you will not develop the
reservoir, and
(ii) Economic justification, including costs, recoverable reserve
estimate, production profiles, and pricing assumptions; and
(16) Any other appropriate data you used in performing your
reservoir evaluations and preparing your reservoir development
strategies.

Sec. 550.298 How long will BOEM take to evaluate and make a decision
on the CID?

(a) The Regional Supervisor will make a decision within 150 calendar
days of receiving your CID. If BOEM does not act within 150 calendar
days, your CID is considered approved.
(b) BOEM may suspend the 150-calendar-day evaluation period if there
is missing, inconclusive, or inaccurate data, or when a well reaches
total depth during the evaluation period. BOEM may also suspend the
evaluation period when a well penetrating a hydrocarbon-bearing
structure reaches total depth during the evaluation period and the data
from that well is needed for the CID. You will receive written
notification from the Regional Supervisor describing the additional
information that is needed, and the evaluation period will resume once
BOEM receives the requested information.
(c) The Regional Supervisor will approve or deny your CID request
based on your commitment to develop economically producible reservoirs
according to sound conservation, engineering, and economic practices.

Sec. 550.299 What operations require approval of the CID?

You may not begin production before you receive BOEM approval of the
CID.

Subpart C_Pollution Prevention and Control

Sec. Sec. 550.300-550.301 [Reserved]

Sec. 550.302 Definitions concerning air quality.

For purposes of Sec. Sec. 550.303 and 550.304 of this part:

[[Page 400]]

Air pollutant means any combination of agents for which the
Environmental Protection Agency (EPA) has established, pursuant to
section 109 of the Clean Air Act, national primary or secondary ambient
air quality standards.
Attainment area means, for any air pollutant, an area which is shown
by monitored data or which is calculated by air quality modeling (or
other methods determined by the Administrator of EPA to be reliable) not
to exceed any primary or secondary ambient air quality standards
established by EPA.
Best available control technology (BACT) means an emission
limitation based on the maximum degree of reduction for each air
pollutant subject to regulation, taking into account energy,
environmental and economic impacts, and other costs. The BACT shall be
verified on a case-by-case basis by the Regional Supervisor and may
include reductions achieved through the application of processes,
systems, and techniques for the control of each air pollutant.
Emission offsets mean emission reductions obtained from facilities,
either onshore or offshore, other than the facility or facilities
covered by the proposed Exploration Plan or Development and Production
Plan.
Existing facility is an OCS facility described in an Exploration
Plan or a Development and Production Plan submitted or approved prior to
June 2, 1980.
Facility means any installation or device permanently or temporarily
attached to the seabed which is used for exploration, development, and
production activities for oil, gas, or sulphur and which emits or has
the potential to emit any air pollutant from one or more sources. All
equipment directly associated with the installation or device shall be
considered part of a single facility if the equipment is dependent on,
or affects the processes of, the installation or device. During
production, multiple installations or devices will be considered to be a
single facility if the installations or devices are directly related to
the production of oil, gas, or sulphur at a single site. Any vessel used
to transfer production from an offshore facility shall be considered
part of the facility while physically attached to it.
Nonattainment area means, for any air pollutant, an area which is
shown by monitored data or which is calculated by air quality modeling
(or other methods determined by the Administrator of EPA to be reliable)
to exceed any primary or secondary ambient air quality standard
established by EPA.
Projected emissions mean emissions, either controlled or
uncontrolled, from a source(s).
Source means an emission point. Several sources may be included
within a single facility.
Temporary facility means activities associated with the construction
of platforms offshore or with facilities related to exploration for or
development of offshore oil and gas resources which are conducted in one
location for less than 3 years.
Volatile organic compound (VOC) means any organic compound which is
emitted to the atmosphere as a vapor. The unreactive compounds are
exempt from the above definition.

Sec. 550.303 Facilities described in a new or revised Exploration Plan
or Development and Production Plan.

(a) New plans. All Exploration Plans and Development and Production
Plans shall include the information required to make the necessary
findings under paragraphs (d) through (i) of this section, and the
lessee shall comply with the requirements of this section as necessary.
(b) Applicability of Sec. 550.303 to existing facilities. (1) The
Regional Supervisor may review any Exploration Plan or Development and
Production Plan to determine whether any facility described in the plan
should be subject to review under this section and has the potential to
significantly affect the air quality of an onshore area. To make these
decisions, the Regional Supervisor shall consider the distance of the
facility from shore, the size of the facility, the number of sources
planned for the facility and their operational status, and the air
quality status of the onshore area.
(2) For a facility identified by the Regional Supervisor in
paragraph (b)(1) of this section, the Regional Supervisor

[[Page 401]]

shall require the lessee to refer to the information required in Sec.
550.218 or Sec. 550.249 of this part and to submit only that
information required to make the necessary findings under paragraphs (d)
through (i) of this section. The lessee shall submit this information
within 120 days of the Regional Supervisor's determination or within a
longer period of time at the discretion of the Regional Supervisor. The
lessee shall comply with the requirements of this section as necessary.
(c) Revised facilities. All revised Exploration Plans and
Development and Production Plans shall include the information required
to make the necessary findings under paragraphs (d) through (i) of this
section. The lessee shall comply with the requirements of this section
as necessary.
(d) Exemption formulas. To determine whether a facility described in
a new, modified, or revised Exploration Plan or Development and
Production Plan is exempt from further air quality review, the lessee
shall use the highest annual-total amount of emissions from the facility
for each air pollutant calculated in Sec. 550.249(a) or Sec.
550.218(a) of this part and compare these emissions to the emission
exemption amount ``E'' for each air pollutant calculated using the
following formulas: E = 3400D \2/3\ for carbon monoxide (CO); and E =
33.3D for total suspended particulates (TSP), sulphur dioxide
(SO2), nitrogen oxides (NOX), and VOC (where E is
the emission exemption amount expressed in tons per year, and D is the
distance of the proposed facility from the closest onshore area of a
State expressed in statute miles). If the amount of these projected
emissions is less than or equal to the emission exemption amount ``E''
for the air pollutant, the facility is exempt from further air quality
review required under paragraphs (e) through (i) of this section.
(e) Significance levels. For a facility not exempt under paragraph
(d) of this section for air pollutants other than VOC, the lessee shall
use an approved air quality model to determine whether the projected
emissions of those air pollutants from the facility result in an onshore
ambient air concentration above the following significance levels:

Significance Levels--Air Pollutant Concentrations
[[micro]g/m\3\]
----------------------------------------------------------------------------------------------------------------
Averaging time (hours)
Air pollutant -------------------------------------------------------------------------------
Annual 24 8 3 1
----------------------------------------------------------------------------------------------------------------
SO2............................. 1 5 .............. 25
TSP............................. 1 5 .............. ..............
NO2............................. 1 .............. .............. ..............
CO.............................. .............. .............. 500 .............. 2,000
----------------------------------------------------------------------------------------------------------------

(f) Significance determinations. (1) The projected emissions of any
air pollutant other than VOC from any facility which result in an
onshore ambient air concentration above the significance level
determined under paragraph (e) of this section for that air pollutant,
shall be deemed to significantly affect the air quality of the onshore
area for that air pollutant.
(2) The projected emissions of VOC from any facility which is not
exempt under paragraph (d) of this section for that air pollutant shall
be deemed to significantly affect the air quality of the onshore area
for VOC.
(g) Controls required. (1) The projected emissions of any air
pollutant other than VOC from any facility, except a temporary facility,
which significantly affect the quality of a nonattainment area, shall be
fully reduced. This shall be done through the application of BACT and,
if additional reductions are necessary, through the application of
additional emission controls or through the acquisition of offshore or
onshore offsets.
(2) The projected emissions of any air pollutant other than VOC from
any facility which significantly affect the air quality of an attainment
or unclassifiable area shall be reduced through the application of BACT.
(i)(A) Except for temporary facilities, the lessee also shall use an
approved

[[Page 402]]

air quality model to determine whether the emissions of TSP or
SO2 that remain after the application of BACT cause the
following maximum allowable increases over the baseline concentrations
established in 40 CFR 52.21 to be exceeded in the attainment or
unclassifiable area:

Maximum Allowable Concentration Increases
[[micro]g/m\3\]
----------------------------------------------------------------------------------------------------------------
Averaging times
-----------------------------------------------
Air pollutant Annual mean 24-hour
\1\ maximum 3-hour maximum
----------------------------------------------------------------------------------------------------------------
Class I:
TSP......................................................... 5 10
SO2......................................................... 2 5 25
Class II:
TSP......................................................... 19 37
SO2......................................................... 20 91 512
Class III:
TSP......................................................... 37 75
SO2......................................................... 40 182 700
----------------------------------------------------------------------------------------------------------------
\1\ For TSP--geometric; For SO2--arithmetric.

(B) No concentration of an air pollutant shall exceed the
concentration permitted under the national secondary ambient air quality
standard or the concentration permitted under the national primary air
quality standard, whichever concentration is lowest for the air
pollutant for the period of exposure. For any period other than the
annual period, the applicable maximum allowable increase may be exceeded
during one such period per year at any one onshore location.
(ii) If the maximum allowable increases are exceeded, the lessee
shall apply whatever additional emission controls are necessary to
reduce or offset the remaining emissions of TSP or SO2 so
that concentrations in the onshore ambient air of an attainment or
unclassifiable area do not exceed the maximum allowable increases.
(3)(i) The projected emissions of VOC from any facility, except a
temporary facility, which significantly affect the onshore air quality
of a nonattainment area shall be fully reduced. This shall be done
through the application of BACT and, if additional reductions are
necessary, through the application of additional emission controls or
through the acquisition of offshore or onshore offsets.
(ii) The projected emissions of VOC from any facility which
significantly affect the onshore air quality of an attainment area shall
be reduced through the application of BACT.
(4)(i) If projected emissions from a facility significantly affect
the onshore air quality of both a nonattainment and an attainment or
unclassifiable area, the regulatory requirements applicable to projected
emissions significantly affecting a nonattainment area shall apply.
(ii) If projected emissions from a facility significantly affect the
onshore air quality of more than one class of attainment area, the
lessee must reduce projected emissions to meet the maximum allowable
increases specified for each class in paragraph (g)(2)(i) of this
section.
(h) Controls required on temporary facilities. The lessee shall
apply BACT to reduce projected emissions of any air pollutant from a
temporary facility which significantly affects the air quality of an
onshore area of a State.
(i) Emission offsets. When emission offsets are to be obtained, the
lessee must demonstrate that the offsets are equivalent in nature and
quantity to the projected emissions that must be reduced after the
application of BACT; a binding commitment exists between the lessee and
the owner or owners of the source or sources; the appropriate air
quality control jurisdiction has been notified of the need to revise the
State Implementation Plan to include the information regarding the
offsets; and the required offsets come from sources which affect the air
quality of

[[Page 403]]

the area significantly affected by the lessee's offshore operations.
(j) Review of facilities with emissions below the exemption amount.
If, during the review of a new, modified, or revised Exploration Plan or
Development and Production Plan, the Regional Supervisor determines or
an affected State submits information to the Regional Supervisor which
demonstrates, in the judgment of the Regional Supervisor, that projected
emissions from an otherwise exempt facility will, either individually or
in combination with other facilities in the area, significantly affect
the air quality of an onshore area, then the Regional Supervisor shall
require the lessee to submit additional information to determine whether
emission control measures are necessary. The lessee shall be given the
opportunity to present information to the Regional Supervisor which
demonstrates that the exempt facility is not significantly affecting the
air quality of an onshore area of the State.
(k) Emission monitoring requirements. The lessee shall monitor, in a
manner approved or prescribed by the Regional Supervisor, emissions from
the facility. The lessee shall submit this information monthly in a
manner and form approved or prescribed by the Regional Supervisor.
(l) Collection of meteorological data. The Regional Supervisor may
require the lessee to collect, for a period of time and in a manner
approved or prescribed by the Regional Supervisor, and submit
meteorological data from a facility.

Sec. 550.304 Existing facilities.

(a) Process leading to review of an existing facility. (1) An
affected State may request that the Regional Supervisor supply basic
emission data from existing facilities when such data are needed for the
updating of the State's emission inventory. In submitting the request,
the State must demonstrate that similar offshore and onshore facilities
in areas under the State's jurisdiction are also included in the
emission inventory.
(2) The Regional Supervisor may require lessees of existing
facilities to submit basic emission data to a State submitting a request
under paragraph (a)(1) of this section.
(3) The State submitting a request under paragraph (a)(1) of this
section may submit information from its emission inventory which
indicates that emissions from existing facilities may be significantly
affecting the air quality of the onshore area of the State. The lessee
shall be given the opportunity to present information to the Regional
Supervisor which demonstrates that the facility is not significantly
affecting the air quality of the State.
(4) The Regional Supervisor shall evaluate the information submitted
under paragraph (a)(3) of this section and shall determine, based on the
basic emission data, available meteorological data, and the distance of
the facility or facilities from the onshore area, whether any existing
facility has the potential to significantly affect the air quality of
the onshore area of the State.
(5) If the Regional Supervisor determines that no existing facility
has the potential to significantly affect the air quality of the onshore
area of the State submitting information under paragraph (a)(3) of this
section, the Regional Supervisor shall notify the State of and explain
the reasons for this finding.
(6) If the Regional Supervisor determines that an existing facility
has the potential to significantly affect the air quality of an onshore
area of the State submitting information under paragraph (a)(3) of this
section, the Regional Supervisor shall require the lessee to refer to
the information requirements under Sec. 550.218 or Sec. 550.249 of
this part and submit only that information required to make the
necessary findings under paragraphs (b) through (e) of this section. The
lessee shall submit this information within 120 days of the Regional
Supervisor's determination or within a longer period of time at the
discretion of the Regional Supervisor. The lessee shall comply with the
requirements of this section as necessary.
(b) Exemption formulas. To determine whether an existing facility is
exempt from further air quality review, the lessee shall use the highest
annual

[[Page 404]]

total amount of emissions from the facility for each air pollutant
calculated in Sec. 550.218(a) or Sec. 550.249(a) of this part and
compare these emissions to the emission exemption amount ``E'' for each
air pollutant calculated using the following formulas: E =
3400D^2/3 for CO; and E = 33.3D for TSP, SO2,
NOX, and VOC (where E is the emission exemption amount
expressed in tons per year, and D is the distance of the facility from
the closest onshore area of the State expressed in statute miles). If
the amount of projected emissions is less than or equal to the emission
exemption amount ``E'' for the air pollutant, the facility is exempt for
that air pollutant from further air quality review required under
paragraphs (c) through (e) of this section.
(c) Significance levels. For a facility not exempt under paragraph
(b) of this section for air pollutants other than VOC, the lessee shall
use an approved air quality model to determine whether projected
emissions of those air pollutants from the facility result in an onshore
ambient air concentration above the following significance levels:

Significance Levels--Air Pollutant Concentrations
[[micro]G/M\3\]
----------------------------------------------------------------------------------------------------------------
Averaging time (hours)
Air pollutant -------------------------------------------------------------------------------
Annual 24 8 3 1
----------------------------------------------------------------------------------------------------------------
SO2............................. 1 5 .............. 25
TSP............................. 1 5 .............. ..............
NO2............................. 1 .............. .............. ..............
CO.............................. .............. .............. 500 .............. 2,000
----------------------------------------------------------------------------------------------------------------

(d) Significance determinations. (1) The projected emissions of any
air pollutant other than VOC from any facility which result in an
onshore ambient air concentration above the significance levels
determined under paragraph (c) of this section for that air pollutant
shall be deemed to significantly affect the air quality of the onshore
area for that air pollutant.
(2) The projected emissions of VOC from any facility which is not
exempt under paragraph (b) of this section for that air pollutant shall
be deemed to significantly affect the air quality of the onshore area
for VOC.
(e) Controls required. (1) The projected emissions of any air
pollutant which significantly affect the air quality of an onshore area
shall be reduced through the application of BACT.
(2) The lessee shall submit a compliance schedule for the
application of BACT. If it is necessary to cease operations to allow for
the installation of emission controls, the lessee may apply for a
suspension of operations under the provisions of 30 CFR 250.174.
(f) Review of facilities with emissions below the exemption amount.
If, during the review of the information required under paragraph (a)(6)
of this section, the Regional Supervisor determines or an affected State
submits information to the Regional Supervisor which demonstrates, in
the judgment of the Regional Supervisor, that projected emissions from
an otherwise exempt facility will, either individually or in combination
with other facilities in the area, significantly affect the air quality
of an onshore area, then the Regional Supervisor shall require the
lessee to submit additional information to determine whether control
measures are necessary. The lessee shall be given the opportunity to
present information to the Regional Supervisor which demonstrates that
the exempt facility is not significantly affecting the air quality of an
onshore area of the State.
(g) Emission monitoring requirements. The lessee shall monitor, in a
manner approved or prescribed by the Regional Supervisor, emissions from
the facility following the installation of emission controls. The lessee
shall submit this information monthly in a manner and form approved or
prescribed by the Regional Supervisor.
(h) Collection of meteorological data. The Regional Supervisor may
require the lessee to collect, for a period of

[[Page 405]]

time and in a manner approved or prescribed by the Regional Supervisor,
and submit meteorological data from a facility.

Subpart D_Leasing Maps and Diagrams

Sec. 550.400 Leasing maps and diagrams.

(a) Any area of the OCS, which has been appropriately platted as
provided in paragraph (b) of this section, may be leased for any mineral
not included in an existing lease issued under the Act or meeting the
requirements of subsection (a) of section 6 of the Act. Before any lease
is offered or issued an area may be:
(1) Withdrawn from disposition pursuant to section 12(a) of the Act;
or
(2) Designated as an area or part of an area restricted from
operation under section 12(d) of the Act.
(b) BOEM will prepare leasing maps and official protraction diagrams
of areas of the OCS. The areas included in each mineral lease will be in
accordance with the appropriate leasing map or official protraction
diagram.

[81 FR 18152, Mar. 30, 2016]

Subparts E-I [Reserved]

Subpart J_Pipelines and Pipeline Rights-of-Way

Sec. 550.1011 Bond requirements for pipeline right-of-way holders.

(a) When you apply for, or are the holder of, a right-of-way, you
must:
(1) Provide and maintain a $300,000 bond (in addition to the bond
coverage required in 30 CFR part 256 and 30 CFR part 556) that
guarantees compliance with all the terms and conditions of the rights-
of-way you hold in an OCS area; and
(2) Provide additional security if the Regional Director determines
that a bond in excess of $300,000 is needed.
(b) For the purpose of this paragraph, there are three areas:
(1) The Gulf of Mexico and the area offshore the Atlantic Coast;
(2) The areas offshore the Pacific Coast States of California,
Oregon, Washington, and Hawaii; and
(3) The area offshore the Coast of Alaska.
(c) If, as the result of a default, the surety on a right-of-way
grant bond makes payment to the Government of any indebtedness under a
grant secured by the bond, the face amount of such bond and the surety's
liability shall be reduced by the amount of such payment.
(d) After a default, a new bond in the amount of $300,000 shall be
posted within 6 months or such shorter period as the Regional Supervisor
may direct. Failure to post a new bond shall be grounds for forfeiture
of all grants covered by the defaulted bond.

Subpart K_Oil and Gas Production Requirements.

Well Tests and Surveys

Sec. 550.1153 When must I conduct a static bottomhole pressure survey?

(a) You must conduct a static bottomhole pressure survey under the
following conditions:

----------------------------------------------------------------------------------------------------------------
If you have . . . Then you must conduct . . .
----------------------------------------------------------------------------------------------------------------
(1) A new producing reservoir, A static bottomhole pressure survey within 90 days after
the date of first continuous production.
(2) A reservoir with three or more producing Annual static bottomhole pressure surveys in a sufficient
completions, number of key wells to establish an average reservoir
pressure. The Regional Supervisor may require that
bottomhole pressure surveys be performed on specific
wells.
----------------------------------------------------------------------------------------------------------------

(b) Your bottomhole pressure survey must meet the following
requirements:
(1) You must shut-in the well for a minimum period of 4 hours to
ensure stabilized conditions; and
(2) The bottomhole pressure survey must consist of a pressure
measurement at mid-perforation, and pressure measurements and gradient
information for at least four gradient stops coming out of the hole.
(c) You must submit to the Regional Supervisor the results of all
static bottomhole pressure surveys on Form

[[Page 406]]

BOEM-140, Bottomhole Pressure Survey Report, within 60 days after the
date of the survey.
(d) The Regional Supervisor may grant a departure from the
requirement to run a static bottomhole pressure survey. To request a
departure, you must submit a justification, along with Form BOEM-0140,
Bottomhole Pressure Survey Report, showing a calculated bottomhole
pressure or any measured data.

[76 FR 64623, Oct. 18, 2011, as amended at 80 FR 57096, Sept. 22, 2015]

Classifying Reservoirs

Sec. 550.1154 How do I determine if my reservoir is sensitive?

(a) You must determine whether each reservoir is sensitive. You must
classify the reservoir as sensitive if:
(1) Under initial conditions it is an oil reservoir with an
associated gas cap;
(2) At any time there are near-critical fluids; or
(3) The reservoir is undergoing enhanced recovery.
(b) For the purposes of this subpart, near-critical fluids are:
(1) Those fluids that occur in high temperature, high-pressure
reservoirs where it is not possible to define the liquid-gas contact; or
(2) Fluids in reservoirs that are near bubble point or dew point
conditions.
(c) The Regional Supervisor may reclassify a reservoir when
available information warrants reclassification.
(d) If available information indicates that a reservoir previously
classified as non-sensitive is now sensitive, you must submit a request
to the Regional Supervisor to reclassify the reservoir. You must include
supporting information, as listed in the table in Sec. 550.1167, with
your request.
(e) If information indicates that a reservoir previously classified
as sensitive is now non-sensitive, you may submit a request to the
Regional Supervisor to reclassify the reservoir. You must include
supporting information, as listed in the table in Sec. 550.1167, with
your request.

Sec. 550.1155 What information must I submit for sensitive reservoirs?

You must submit to the Regional Supervisor an original and two
copies of Form BOEM-0127; one of the copies must be a public information
copy in accordance with Sec. Sec. 550.186 and 550.197, and marked
``Public Information.'' You must also submit two copies of the
supporting information, as listed in the table in Sec. 550.1167. You
must submit this information:
(a) Within 45 days after beginning production from the reservoir or
discovering that it is sensitive;
(b) At least once during the calendar year, but you do not need to
resubmit unrevised structure maps (Sec. 550.1167(a)(2)) or previously
submitted well logs (Sec. 550.1167(c)(1));
(c) Within 45 days after you revise reservoir parameters; and
(d) Within 45 days after the Regional Supervisor classifies the
reservoir as sensitive under Sec. 550.1154(c).

Other Requirements

Sec. 550.1165 What must I do for enhanced recovery operations?

(a) [Reserved]
(b) Before initiating enhanced recovery operations, you must submit
a proposed plan to the BSEE Regional Supervisor and receive approval for
pressure maintenance, secondary or tertiary recovery, cycling, and
similar recovery operations intended to increase the ultimate recovery
of oil and gas from a reservoir. The proposed plan must include, for
each project reservoir, a geologic and engineering overview, Form BOEM-
0127 (submitted to BOEM) and supporting data as required in Sec.
550.1167, 30 CFR 250.1167, and any additional information required by
the BSEE Regional Supervisor.
(c) [Reserved]

Sec. 550.1166 What additional reporting is required for developments
in the Alaska OCS Region?

(a)-(b) [Reserved]
(c) Every time you are required to submit Form BOEM-0127 under Sec.
550.1155, you must request an MER for each producing sensitive reservoir
in

[[Page 407]]

the Alaska OCS Region, unless otherwise instructed by the Regional
Supervisor.

Sec. 550.1167 What information must I submit with forms and for approvals?

You must submit the supporting information listed in the following
table with the form identified in column 1 and for the approval required
under this subpart identified in column 2:

----------------------------------------------------------------------------------------------------------------
Reservoir
SRI BOEM-0127 (2 copies) reclassification
----------------------------------------------------------------------------------------------------------------
(a) Maps: ........................ ........................
(1) Base map with surface, bottomhole, and completion ........................
locations with respect to the unit or lease line and
the orientation of representative seismic lines or
cross-sections.........................................
(2) Structure maps with penetration point and subsea [radic] [radic]
depth for each well penetrating the reservoirs,
highlighting subject wells; reservoir boundaries; and
original and current fluid levels......................
(3) Net sand isopach with total net sand penetrated for *
each well, identified at the penetration point.........
(4) Net hydrocarbon isopach with net feet of pay for *
each well, identified at the penetration point.........
(b) Seismic data: ........................ ........................
(1) Representative seismic lines, including strike and ........................
dip lines that confirm the structure; indicate polarity
(2) Amplitude extraction of seismic horizon, if ........................ [radic]
applicable.............................................
(c) Logs: ........................ ........................
(1) Well log sections with tops and bottoms of the [radic] [radic]
reservoir(s) and proposed or existing perforations.....
(2) Structural cross-sections showing the subject well ........................ [radic]
and nearby wells.......................................
(d) Engineering data: ........................ ........................
(1) Estimated recoverable reserves for each well [radic]
completion in the reservoir; total recoverable reserves
for each reservoir; method of calculation; reservoir
parameters used in volumetric and decline curve
analysis...............................................
(2) Well schematics showing current and proposed ........................
conditions.............................................
(3) The drive mechanism of each reservoir............... [radic] [radic]
(4) Pressure data, by date, and whether they are ........................ [radic]
estimated or measured..................................
(5) Production data and decline curve analysis ........................ [radic]
indicative of the reservoir performance................
(6) Reservoir simulation with the reservoir parameters ........................ *
used, history matches, and prediction runs (include
proposed development scenario).........................
(e) General information: ........................ ........................
(1) Detailed economic analysis.......................... ........................ ........................
(2) Reservoir name and whether or not it is competitive [radic] [radic]
as defined under Sec. 250.105........................
(3) Operator name, lessee name(s), block, lease number, ........................
royalty rate, and unit number (if applicable) of all
relevant leases........................................
(4) Geologic overview of project........................ ........................ [radic]
(5) Explanation of why the proposed completion scenario ........................
will maximize ultimate recovery........................
(6) List of all wells in subject reservoirs that have ........................ [radic]
ever produced or been used for injection...............
----------------------------------------------------------------------------------------------------------------
[radic] Required.
* Additional items the Regional Supervisor may request.
Note: All maps must be at a standard scale and show lease and unit lines. The Regional Supervisor may waive
submittal of some of the required data on a case-by-case basis.

[[Page 408]]

(f) Depending on the type of approval requested, you must submit the
appropriate payment of the service fee(s) listed in Sec. 550.125,
according to the instructions in Sec. 550.126.

Subparts L-M [Reserved]

Subpart N_Outer Continental Shelf Civil Penalties

Outer Continental Shelf Lands Act Civil Penalties

Sec. 550.1400 How does BOEM begin the civil penalty process?

This subpart explains BOEM's civil penalty procedures whenever a
lessee, operator or other person engaged in oil, gas, sulphur or other
minerals operations in the OCS has a violation. Whenever BOEM
determines, on the basis of available evidence, that a violation
occurred and a civil penalty review is appropriate, it will prepare a
case file. BOEM will appoint a Reviewing Officer.

Sec. 550.1401 Index table.

The following table is an index of the sections in this subpart:

------------------------------------------------------------------------

------------------------------------------------------------------------
(a) Definitions......................... Sec. 550.1402
(b) What is the maximum civil penalty?.. Sec. 550.1403
(c) Which violations will BOEM review Sec. 550.1404
for potential civil penalties?.
(d) When is a case file developed?...... Sec. 550.1405
(e) When will BOEM notify me and provide Sec. 550.1406
penalty information?.
(f) How do I respond to the letter of Sec. 550.1407
notification?.
(g) When will I be notified of the Sec. 550.1408
Reviewing Officer's decision?.
(h) What are my appeal rights?.......... Sec. 550.1409
------------------------------------------------------------------------

Sec. 550.1402 Definitions.

Terms used in this subpart have the following meaning:
Case file means a BOEM document file containing information and the
record of evidence related to the alleged violation.
Civil penalty means a fine. It is a BOEM regulatory enforcement tool
used in addition to Notices of Incidents of Noncompliance and directed
suspensions of production or other operations.
Reviewing Officer means a BOEM employee assigned to review case
files and assess civil penalties.
Violation means failure to comply with the Outer Continental Shelf
Lands Act (OCSLA) or any other applicable laws, with any regulations
issued under the OCSLA, or with the terms or provisions of leases,
licenses, permits, rights-of-way, or other approvals issued under the
OCSLA.
Violator means a person responsible for a violation.

Sec. 550.1403 What is the maximum civil penalty?

The maximum civil penalty is $43,576 per day per violation.

[83 FR 8933, Mar. 2, 2018]

Sec. 550.1404 Which violations will BOEM review
for potential civil penalties?

BOEM will review each of the following violations for potential
civil penalties:
(a) Violations that you do not correct within the period BOEM
grants;
(b)-(c) [Reserved]
(d) Violations of the oil spill financial responsibility
requirements at 30 CFR part 553.

Sec. 550.1405 When is a case file developed?

BOEM will develop a case file during its investigation of the
violation, and forward it to a Reviewing Officer if any of the
conditions in Sec. 550.1404 exist. The Reviewing Officer will review
the case file and determine if a civil penalty is appropriate. The
Reviewing Officer

[[Page 409]]

may administer oaths and issue subpoenas requiring witnesses to attend
meetings, submit depositions, or produce evidence.

Sec. 550.1406 When will BOEM notify me and provide penalty information?

If the Reviewing Officer determines that a civil penalty should be
assessed, the Reviewing Officer will send the violator a letter of
notification. The letter of notification will include:
(a) The amount of the proposed civil penalty;
(b) Information on the violation(s); and
(c) Instruction on how to obtain a copy of the case file, schedule a
meeting, submit information, or pay the penalty.

Sec. 550.1407 How do I respond to the letter of notification?

Sec. 550.1408 When will I be notified of the Reviewing Officer's decision?

Sec. 550.1409 What are my appeal rights?

(a) When you receive the Reviewing Officer's final decision, you
have 60 days to either pay the penalty or file an appeal in accordance
with 30 CFR part 590, subpart A.
(b) If you file an appeal, you must either:
(1) Submit a surety bond in the amount of the penalty to the
appropriate Leasing Office in the Region where the penalty was assessed,
following instructions that the Reviewing Officer will include in the
final decision; or
(2) Notify the appropriate Leasing Office, in the Region where the
penalty was assessed, that you want your lease-specific/area-wide bond
on file to be used as the bond for the penalty amount.
(c) If you choose the alternative in paragraph (b)(2) of this
section, the BOEM Regional Director may require additional security
(i.e., security in excess of your existing bond) to ensure sufficient
coverage during an appeal. In that event, the Regional Director will
require you to post the supplemental bond with the regional office in
the same manner as under Sec. 556.53(d) through (f) of this chapter. If
the Regional Director determines the appeal should be covered by a
lease-specific abandonment account then you must establish an account
that meets the requirements of Sec. 556.56.
(d) If you do not either pay the penalty or file a timely appeal,
BOEM will take one or more of the following actions:
(1) We will collect the amount you were assessed, plus interest,
late payment charges, and other fees as provided by law, from the date
you received the Reviewing Officer's final decision until the date we
receive payment;
(2) We may initiate additional enforcement, including, if
appropriate, cancellation of the lease, right-of-way, license, permit,
or approval, or the forfeiture of a bond under this part; or
(3) We may bar you from doing further business with the Federal
Government according to Executive Orders 12549 and 12689, and section
2455 of the Federal Acquisition Streamlining Act of 1994, 31 U.S.C.
6101. The Department of the Interior's regulations implementing these
authorities are found at 43 CFR part 12, subpart D.

Federal Oil and Gas Royalty Management Act Civil Penalties Definitions

Sec. 550.1450 What definitions apply to this subpart?

The terms used in this subpart have the same meaning as in 30 U.S.C.
1702.

[[Page 410]]

Penalties After a Period to Correct

Sec. 550.1451 What may BOEM do if I violate a statute, regulation, order,
or lease term relating to a Federal oil and gas lease?

(a) If we believe that you have not followed any requirement of a
statute, regulation, order, or lease term for any Federal oil or gas
lease, we may send you a Notice of Noncompliance informing you what the
violation is and what you need to do to correct it to avoid civil
penalties under 30 U.S.C. 1719(a) and (b).
(b) We will serve the Notice of Noncompliance by registered mail or
personal service using the most current address on file as maintained by
the BOEM Leasing Office in your respective Region.

Sec. 550.1452 What if I correct the violation?

Sec. 550.1453 What if I do not correct the violation?

Sec. 550.1454 How may I request a hearing on the record
on a Notice of Noncompliance?

You may request a hearing on the record on a Notice of Noncompliance
by filing a request within 30 days of the date you received the Notice
of Noncompliance with the Hearings Division (Departmental), Office of
Hearings and Appeals, U.S. Department of the Interior, 351 South West
Temple, Suite 6.300, Salt Lake City, Utah 84101. You may do this
regardless of whether you correct the violations identified in the
Notice of Noncompliance.

[76 FR 64623, Oct. 18, 2011, as amended at 80 FR 57096, Sept. 22, 2015]

Sec. 550.1455 Does my request for a hearing on the record
affect the penalties?

(a) If you do not correct the violations identified in the Notice of
Noncompliance, the penalties will continue to accrue even if you request
a hearing on the record.
(b) You may petition the Hearings Division (Departmental) of the
Office of Hearings and Appeals, to stay the accrual of penalties pending
the hearing on the record and a decision by the Administrative Law Judge
under Sec. 550.1472.
(1) You must file your petition within 45 calendar days of receiving
the Notice of Noncompliance.
(2) To stay the accrual of penalties, you must post a bond or other
surety instrument, or demonstrate financial solvency, using the
standards and requirements as prescribed in Sec. Sec. 550.1490 through
550.1497, for the principal amount of any unpaid amounts due that are
the subject of the Notice of Noncompliance, including interest thereon,
plus the amount of any penalties accrued before the date a stay becomes
effective.
(3) The Hearings Division will grant or deny the petition under 43
CFR 4.21(b).

[[Page 411]]

Sec. 550.1456 May I request a hearing on the record regarding the amount
of a civil penalty if I did not request a hearing
on the Notice of Noncompliance?

(a) You may request a hearing on the record to challenge only the
amount of a civil penalty when you receive a Notice of Civil Penalty, if
you did not previously request a hearing on the record under Sec.
550.1454. If you did not request a hearing on the record on the Notice
of Noncompliance under Sec. 550.1454, you may not contest your
underlying liability for civil penalties.
(b) You must file your request within 10 days after you receive the
Notice of Civil Penalty with the Hearings Division (Departmental),
Office of Hearings and Appeals, U.S. Department of the Interior, 351
South West Temple, Suite 6.300, Salt Lake City, Utah 84101.

[76 FR 64623, Oct. 18, 2011, as amended at 80 FR 57096, Sept. 22, 2015]

Penalties Without a Period to Correct

Sec. 550.1460 May I be subject to penalties without prior notice
and an opportunity to correct?

The Federal Oil and Gas Royalty Management Act sets out several
specific violations for which penalties accrue without an opportunity to
first correct the violation.
(a) [Reserved]
(b) Under 30 U.S.C. 1719(d), you may be subject to civil penalties
of up to $25,000 per day for each day each violation continues if you:
(1) Knowingly or willfully prepare, maintain, or submit false,
inaccurate, or misleading reports, notices, affidavits, records, data,
or other written information;
(2)-(3) [Reserved]

Sec. 550.1461 How will BOEM inform me of violations
without a period to correct?

Sec. 550.1462 How may I request a hearing on the record
on a Notice of Noncompliance regarding violations without a period to correct?

You may request a hearing on the record of a Notice of Noncompliance
regarding violations without a period to correct by filing a request
within 30 days after you receive the Notice of Noncompliance with the
Hearings Division (Departmental), Office of Hearings and Appeals, U.S.
Department of the Interior, 351 South West Temple, Suite 6.300, Salt
Lake City, Utah 84101. You may do this regardless of whether you correct
the violations identified in the Notice of Noncompliance.

[76 FR 64623, Oct. 18, 2011, as amended at 80 FR 57096, Sept. 22, 2015]

Sec. 550.1463 Does my request for a hearing on the record
affect the penalties?

(a) If you do not correct the violations identified in the Notice of
Noncompliance regarding violations without a period to correct, the
penalties will continue to accrue even if you request a hearing on the
record.
(b) You may ask the Hearings Division (Departmental) to stay the
accrual of penalties pending the hearing on the record and a decision by
the Administrative Law Judge under Sec. 550.1472.
(1) You must file your petition within 45 calendar days after you
receive the Notice of Noncompliance.
(2) To stay the accrual of penalties, you must post a bond or other
surety instrument, or demonstrate financial solvency, using the
standards and requirements as prescribed in Sec. Sec. 550.1490 through
550.1497, for the principal amount of any unpaid amounts due that are
the subject of the Notice of Noncompliance, including interest thereon,
plus the amount of any penalties accrued before the date a stay becomes
effective.
(3) The Hearings Division will grant or deny the petition under 43
CFR 4.21(b).

[[Page 412]]

Sec. 550.1464 May I request a hearing on the record regarding the amount
of a civil penalty if I did not request a hearing
on the Notice of Noncompliance?

(a) You may request a hearing on the record to challenge only the
amount of a civil penalty when you receive a Notice of Civil Penalty
regarding violations without a period to correct, if you did not
previously request a hearing on the record under Sec. 550.1462. If you
did not request a hearing on the record on the Notice of Noncompliance
under Sec. 550.1462, you may not contest your underlying liability for
civil penalties.
(b) You must file your request within 10 days after you receive
Notice of Civil Penalty with the Hearings Division (Departmental),
Office of Hearings and Appeals, U.S. Department of the Interior, 351
South West Temple, Suite 6.300, Salt Lake City, Utah 84101.

[76 FR 64623, Oct. 18, 2011, as amended at 80 FR 57096, Sept. 22, 2015]

General Provisions

Sec. 550.1470 How does BOEM decide what the amount of the penalty should be?

We determine the amount of the penalty by considering the severity
of the violations, your history of compliance, and if you are a small
business.

Sec. 550.1471 Does the penalty affect whether I owe interest?

If you do not pay the penalty by the date required under Sec.
550.1475(d), BOEM will assess you late payment interest on the penalty
amount at the same rate interest is assessed under 30 CFR 1218.54.

Sec. 550.1472 How will the Office of Hearings and Appeals
conduct the hearing on the record?

If you request a hearing on the record under Sec. 550.1454, Sec.
550.1456, Sec. 550.1462, or Sec. 550.1464, the hearing will be
conducted by a Departmental Administrative Law Judge from the Office of
Hearings and Appeals. After the hearing, the Administrative Law Judge
will issue a decision in accordance with the evidence presented and
applicable law.

Sec. 550.1473 How may I appeal the Administrative Law Judge's decision?

If you are adversely affected by the Administrative Law Judge's
decision, you may appeal that decision to the Interior Board of Land
Appeals under 43 CFR part 4, subpart E.

Sec. 550.1474 May I seek judicial review of the decision
of the Interior Board of Land Appeals?

Sec. 550.1475 When must I pay the penalty?

(a) You must pay the amount of the Notice of Civil Penalty issued
under Sec. 550.1453 or Sec. 550.1461, if you do not request a hearing
on the record under Sec. 550.1454, Sec. 550.1456, Sec. 550.1462, or
Sec. 550.1464
(b) If you request a hearing on the record under Sec. 550.1454,
Sec. 550.1456, Sec. 550.1462, or Sec. 550.1464, but you do not appeal
the determination of the Administrative Law Judge to the Interior Board
of Land Appeals under Sec. 550.1473, you must pay the amount assessed
by the Administrative Law Judge.
(c) If you appeal the determination of the Administrative Law Judge
to the Interior Board of Land Appeals, you must pay the amount assessed
in the IBLA decision.
(d) You must pay the penalty assessed within 40 days after:
(1) You received the Notice of Civil Penalty, if you did not request
a hearing on the record under either Sec. 550.1454, Sec. 550.1456,
Sec. 550.1462, or Sec. 550.1464;
(2) You received an Administrative Law Judge's decision under Sec.
550.1472, if you obtained a stay of the accrual of penalties pending the
hearing on the record under Sec. 550.1455(b) or Sec. 550.1463(b) and
did not appeal the Administrative Law Judge's determination to the IBLA
under Sec. 550.1473;
(3) You received an IBLA decision under Sec. 550.1473 if the IBLA
continued the stay of accrual of penalties pending its decision and you
did not seek judicial review of the IBLA's decision; or

[[Page 413]]

(4) A final non-appealable judgment of a court of competent
jurisdiction is entered, if you sought judicial review of the IBLA's
decision and the Department or the appropriate court suspended
compliance with the IBLA's decision pending the adjudication of the
case.
(e) If you do not pay, that amount is subject to collection under
the provisions of Sec. 550.1477.

Sec. 550.1476 Can BOEM reduce my penalty once it is assessed?

Under 30 U.S.C. 1719(g), the Director or his or her delegate may
compromise or reduce civil penalties assessed under this part.

Sec. 550.1477 How may BOEM collect the penalty?

(a) BOEM may use all available means to collect the penalty
including, but not limited to:
(1) Requiring the lease surety, for amounts owed by lessees, to pay
the penalty;
(2) Deducting the amount of the penalty from any sums the United
States owes to you; and
(3) Using judicial process to compel your payment under 30 U.S.C.
1719(k).
(b) If the Department uses judicial process, or if you seek judicial
review under Sec. 550.1474 and the court upholds assessment of a
penalty, the court shall have jurisdiction to award the amount assessed
plus interest assessed from the date of the expiration of the 90-day
period referred to in Sec. 550.1474. The amount of any penalty, as
finally determined, may be deducted from any sum owing to you by the
United States.

Criminal Penalties

Sec. 550.1480 May the United States criminally prosecute me for violations
under Federal oil and gas leases?

If you commit an act for which a civil penalty is provided at 30
U.S.C. 1719(d) and Sec. 550.1460(b), the United States may pursue
criminal penalties as provided at 30 U.S.C. 1720, in addition to any
authority for prosecution under other statutes.

Bonding Requirements

Sec. 550.1490 What standards must my BOEM-specified surety instrument meet?

(a) A BOEM-specified surety instrument must be in a form specified
in BOEM instructions. BOEM will give you written information and
standard forms for BOEM-specified surety instrument requirements.
(b) BOEM will use a bank-rating service to determine whether a
financial institution has an acceptable rating to provide a surety
instrument adequate to indemnify the lessor from loss or damage.
(1) Administrative appeal bonds must be issued by a qualified surety
company which the Department of the Treasury has approved.
(2) Irrevocable letters of credit or certificates of deposit must be
from a financial institution acceptable to BOEM with a minimum 1-year
period of coverage subject to automatic renewal up to 5 years.

Sec. 550.1491 How will BOEM determine the amount of my bond
or other surety instrument?

(a) BOEM bond-approving officer may approve your surety if he or she
determines that the amount is adequate to guarantee payment. The amount
of your surety may vary depending on the form of the surety and how long
the surety is effective.
(1) The amount of the BOEM-specified surety instrument must include
the principal amount owed under the Notice of Noncompliance or Notice of
Civil Penalty plus any accrued interest we determine is owed plus
projected interest for a 1-year period.
(2) Treasury book-entry bond or note amounts must be equal to at
least 120 percent of the required surety amount.
(b) If your appeal is not decided within 1 year from the filing
date, you must increase the surety amount to cover additional estimated
interest for another 1-year period. You must continue to do this
annually on the date your appeal was filed. We will determine the
additional estimated interest and notify you of the amount so you can
amend your surety instrument.

[[Page 414]]

(c) You may submit a single surety instrument that covers multiple
appeals. You may change the instrument to add new amounts under appeal
or remove amounts that have been adjudicated in your favor or that you
have paid, if you:
(1) Amend the single surety instrument annually on the date you
filed your first appeal; and
(2) Submit a separate surety instrument for new amounts under appeal
until you amend the instrument to cover the new appeals.

Financial Solvency Requirements

Sec. 550.1495 How do I demonstrate financial solvency?

(a) To demonstrate financial solvency under this part, you must
submit an audited consolidated balance sheet, and, if requested by the
BOEM bond-approving officer, up to 3 years of tax returns to BOEM using
the U.S. Postal Service, private delivery, courier, or overnight
delivery at:
(1) For Alaska OCS: BOEM Alaska OCS Region, 3801 Centerpoint Drive,
Suite 500, Anchorage, AK 99503, (907) 334-5200.
(2) For Gulf of Mexico and Atlantic OCS: BOEM Gulf of Mexico OCS
Region, 1201 Elmwood Park Boulevard, New Orleans, LA 70123-2394, (800)
200-4853.
(3) For Pacific OCS: BOEM Pacific OCS Region, 760 Paseo Camarillo,
Suite 102 (CM 102), Camarillo, CA 93010, (805) 384-6305.
(b) You must submit an audited consolidated balance sheet annually,
and, if requested, additional annual tax returns on the date BOEM first
determined that you demonstrated financial solvency as long as you have
active appeals, or whenever BOEM requests.
(c) If you demonstrate financial solvency in the current calendar
year, you are not required to redemonstrate financial solvency for new
appeals of orders during that calendar year unless you file for
protection under any provision of the U.S. Bankruptcy Code (Title 11 of
the United States Code), or BOEM notifies you that you must
redemonstrate financial solvency.

[76 FR 64623, Oct. 18, 2011, as amended at 80 FR 57096, Sept. 22, 2015]

Sec. 550.1496 How will BOEM determine if I am financially solvent?

(a) BOEM bond-approving officer will determine your financial
solvency by examining your total net worth, including, as appropriate,
the net worth of your affiliated entities.
(b) If your net worth, minus the amount we would require as surety
under Sec. Sec. 550.1490 and 550.1491 for all orders you have appealed
is greater than $300 million, you are presumptively deemed financially
solvent, and we will not require you to post a bond or other surety
instrument.
(c) If your net worth, minus the amount we would require as surety
under Sec. Sec. 550.1490 and 550.1491 for all orders you have appealed
is less than $300 million, you must submit the following to BOEM by one
of the methods in Sec. 550.1495(a):
(1) A written request asking us to consult a business-information,
or credit-reporting service or program to determine your financial
solvency; and
(2) A nonrefundable $50 processing fee:
(i) You must pay the processing fee to us following the requirements
for making payments found in 30 CFR 550.126. You are required to use
Electronic Funds Transfer (EFT) for these payments;
(ii) You must submit the fee with your request under paragraph
(c)(1) of this section, and then annually on the date we first
determined that you demonstrated financial solvency, as long as you are
not able to demonstrate financial solvency under paragraph (a) of this
section and you have active appeals.
(d) If you request that we consult a business-information or credit-
reporting service or program under paragraph (c) of this section:
(1) We will use criteria similar to that which a potential creditor
would use to lend an amount equal to the bond or other surety instrument
we would require under Sec. Sec. 550.1490 and 550.1491;
(2) For us to consider you financially solvent, the business-
information or credit-reporting service or program must demonstrate your
degree of risk as low to moderate:

[[Page 415]]

(i) If our bond-approving officer determines that the business-
information or credit-reporting service or program information
demonstrates your financial solvency to our satisfaction, our bond-
approving officer will not require you to post a bond or other surety
instrument under Sec. Sec. 550.1490 and 550.1491;
(ii) If our bond-approving officer determines that the business-
information or credit-reporting service or program information does not
demonstrate your financial solvency to our satisfaction, our bond-
approving officer will require you to post a bond or other surety
instrument under Sec. Sec. 550.1490 and 550.1491 or pay the obligation.

Sec. 550.1497 When will BOEM monitor my financial solvency?

(a) If you are presumptively financially solvent under Sec.
550.1496(b), BOEM will determine your net worth as described under
Sec. Sec. 550.1496(b) and (c) to evaluate your financial solvency at
least annually on the date we first determined that you demonstrated
financial solvency as long as you have active appeals and each time you
appeal a new order.
(b) If you ask us to consult a business-information or credit-
reporting service or program under Sec. 550.1496(c), we will consult a
service or program annually as long as you have active appeals and each
time you appeal a new order.
(c) If our bond-approving officer determines that you are no longer
financially solvent, you must post a bond or other BOEM-specified surety
instrument under Sec. Sec. 550.1490 and 550.1491.

Subparts O-S [Reserved]

PART 551_GEOLOGICAL AND GEOPHYSICAL (G&G) EXPLORATIONS OF
THE OUTER CONTINENTAL SHELF--Table of Contents

Sec.
551.1 Definitions.
551.2 Purpose of this part.
551.3 Authority and applicability of this part.
551.4 Types of G&G activities that require permits or Notices.
551.5 Applying for permits or filing Notices.
551.6 Obligations and rights under a permit or a Notice.
551.7 Test drilling activities under a permit.
551.8 Inspection and reporting requirements for activities under a
permit.
551.9 Temporarily stopping, canceling, or relinquishing activities
approved under a permit.
551.10 Penalties and appeals.
551.11 Submission, inspection, and selection of geological data and
information collected under a permit and processed by
permittees or third parties.
551.12 Submission, inspection, and selection of geophysical data and
information collected under a permit and processed by
permittees or third parties.
551.13 Reimbursement for the costs of reproducing data and information
and certain processing costs.
551.14 Protecting and disclosing data and information submitted to BOEM
under a permit.
551.15 Authority for information collection.

Authority: Section 104, Public Law 97-451, 96 Stat. 2451 (30 U.S.C.
1714), Public Law 109-432, Div C, Title I, 120 Stat. 3000; 30 U.S.C.
1751; 31 U.S.C. 9701; 43 U.S.C. 1334; 33 U.S.C. 2704, 2716; E.O. 12777,
as amended; 43 U.S.C. 1331 et seq., 43 U.S.C. 1337.

Source: 76 FR 64623, Oct. 18, 2011, unless otherwise noted.

Sec. 551.1 Definitions.

[[Page 416]]

Archaeological resources mean any material remains of human life or
activities that are at least 50 years of age and of archaeological
interest.
Coastal environment means the physical, atmospheric, and biological
components, conditions, and factors that interactively determine the
productivity, state, condition, and quality of the terrestrial ecosystem
from the shoreline inward to the boundaries of the coastal zone.
Coastal Zone means the coastal waters (including the lands therein
and thereunder) and the adjacent shorelands (including the waters
therein and thereunder), strongly influenced by each other and in
proximity to the shorelines of the several coastal States and extends
seaward to the outer limit of the U.S. territorial sea.
Coastal Zone Management Act means the Coastal Zone Management Act of
1972, as amended (16 U.S.C. 1451 et seq.).
Data means facts, statistics, measurements, or samples that have not
been analyzed, processed, or interpreted.
Deep stratigraphic test means drilling that involves the penetration
into the sea bottom of more than 500 feet (152 meters).
Director means the Director of the Bureau of Ocean Energy
Management, U.S. Department of the Interior, or a subordinate authorized
to act on the Director's behalf.
Exploration means the commercial search for oil, gas, and sulphur.
Activities classified as exploration include, but are not limited to:
(1) Geological and geophysical marine and airborne surveys where
magnetic, gravity, seismic reflection, seismic refraction, gas sniffers,
coring, or other systems are used to detect or imply the presence of
oil, gas, or sulphur; and
(2) Any drilling, whether on or off a geological structure.
Geological and geophysical scientific research means any oil, gas,
or sulphur related investigation conducted in the OCS for scientific
and/or research purposes. Geological, geophysical, and geochemical data
and information gathered and analyzed are made available to the public
for inspection and reproduction at the earliest practicable time. The
term does not include commercial geological or geophysical exploration
or research.
Geological exploration means exploration that uses geological and
geochemical techniques (e.g., coring and test drilling, well logging,
and bottom sampling) to produce data and information on oil, gas, and
sulphur resources in support of possible exploration and development
activities. The term does not include geological scientific research.
Geological information means geological or geochemical data that
have been analyzed, processed, or interpreted.
Geophysical data means measurements that have not been processed or
interpreted.
Geophysical exploration means exploration that utilizes geophysical
techniques (e.g., gravity, magnetic, electromagnetic, or seismic) to
produce data and information on oil, gas, and sulphur resources in
support of possible exploration and development activities. The term
does not include geophysical scientific research.
Geophysical information means geophysical data that have been
processed or interpreted.
Governor means the Governor of a State or the person or entity
lawfully designated to exercise the powers granted to a Governor
pursuant to the Act.
Human environment means the physical, social, and economic
components, conditions, and factors which interactively determine the
state, condition, and quality of living conditions, employment, and
health of those affected, directly or indirectly, by activities
occurring on the OCS.
Hydrocarbon occurrence means the direct or indirect detection during
drilling operations of any liquid or gaseous hydrocarbons by examination
of well cuttings, cores, gas detector readings, formation fluid tests,
wireline logs, or by any other means. The term does not include
background gas, minor accumulations of gas, or heavy oil residues on
cuttings and cores.
Interpreted geological information means knowledge, often in the
form of schematic cross sections, 3-dimensional representations, and
maps, developed by determining the geological

[[Page 417]]

significance of geological data and analyzed and processed geologic
information.
Interpreted geophysical information means knowledge, often in the
form of seismic cross sections, 3-dimensional representations, and maps,
developed by determining the geological significance of geophysical data
and processed geophysical information.
Lease means an agreement which is issued under section 8 or
maintained under section 6 of the Act and which authorizes exploration
for, and development and production of, minerals or the area covered by
that authorization, whichever is required by the context.
Lessee means a person who has entered into, or is the BOEM approved
assignee of, a lease with the United States to explore for, develop, and
produce the leased minerals. The term ``lessee'' also includes an owner
of operating rights.
Marine environment means the physical, atmospheric, and biological
components, conditions, and factors that interactively determine the
quality of the marine ecosystem in the coastal zone and in the OCS.
Material remains mean physical evidence of human habitation,
occupation, use, or activity, including the site, location, or context
in which such evidence is situated.
Minerals mean oil, gas, sulphur, geopressured-geothermal and
associated resources, and all other minerals which are authorized by an
Act of Congress to be produced from public lands as defined in section
103 of the Federal Land Policy and Management Act of 1976 (43 U.S.C.
1702).
Notice means a written statement of intent to conduct geological or
geophysical scientific research related to oil, gas, and sulphur in the
OCS other than under a permit.
Oil, gas, and sulphur means oil, gas, sulphur, geopressured-
geothermal, and associated resources.
Outer Continental Shelf (OCS) means all submerged lands lying
seaward and outside the area of lands beneath navigable waters as
defined in section 2 of the Submerged Lands Act (43 U.S.C. 1301), and of
which the subsoil and seabed appertain to the United States and are
subject to its jurisdiction and control.
Permit means the contract or agreement, other than a lease, issued
pursuant to this part, under which a person acquires the right to
conduct on the OCS, in accordance with appropriate statutes,
regulations, and stipulations:
(1) Geological exploration for mineral resources;
(2) Geophysical exploration for mineral resources;
(3) Geological scientific research; or
(4) Geophysical scientific research.
Permittee means the person authorized by a permit issued pursuant to
this part to conduct activities on the OCS.
Person means a citizen or national of the United States; an alien
lawfully admitted for permanent residence in the United States as
defined in section 8 U.S.C. 1101(a)(20); a private, public, or municipal
corporation organized under the laws of the United States or of any
State or territory thereof; and associations of such citizens,
nationals, resident aliens, or private, public, or municipal
corporations, States, or political subdivisions of States or anyone
operating in a manner provided for by treaty or other applicable
international agreements. The term does not include Federal agencies.
Processed geological or geophysical information means data collected
under a permit and later processed or reprocessed. Processing involves
changing the form of data so as to facilitate interpretation. Processing
operations may include, but are not limited to, applying corrections for
known perturbing causes, rearranging or filtering data, and combining or
transforming data elements. Reprocessing is the additional processing
other than ordinary processing used in the general course of evaluation.
Reprocessing operations may include varying identified parameters for
the detailed study of a specific problem area. Reprocessing may occur
several years after the original processing date. Reprocessing is
determined to be completed on the date that the reprocessed information
is first available in a useable format for in-house interpretation by
BOEM or the permittee, or becomes first available to

[[Page 418]]

third parties via sale, trade, license agreement, or other means.
Secretary means the Secretary of the Interior or a subordinate
authorized to act on the Secretary's behalf.
Shallow test drilling means drilling into the sea bottom to depths
less than those specified in the definition of a deep stratigraphic
test.
Significant archaeological resource means those archaeological
resources that meet the criteria of significance for eligibility to the
National Register of Historic Places as defined in 36 CFR 60.4.
Third Party means any person other than the permittee or a
representative of the United States, including all persons who obtain
data or information acquired under a permit from the permittee, or from
another third party, by sale, trade, license agreement, or other means.
Violation means a failure to comply with any provision of the Act,
or a provision of a regulation or order issued under the Act, or any
provision of a lease, license, or permit issued under the Act.
You means a person who applies for and/or obtains a permit, or files
a Notice to conduct geological or geophysical exploration or scientific
research related to oil, gas, and sulphur in the OCS.

Sec. 551.2 Purpose of this part.

(a) To allow you to conduct G&G activities in the OCS related to
oil, gas, and sulphur on unleased lands or on lands under lease to a
third party.
(b) To ensure that you carry out G&G activities in a safe and
environmentally sound manner so as to prevent harm or damage to, or
waste of, any natural resources (including any mineral deposit in areas
leased or not leased), any life (including fish and other aquatic life),
property, or the marine, coastal, or human environment.
(c) To inform you and third parties of your legal and contractual
obligations.
(d) To inform you and third parties of the U.S. Government's rights
to access G&G data and information collected under permit in the OCS,
reimbursement for submittal of data and information, and the proprietary
terms of data and information submitted to, and retained by, BOEM.

Sec. 551.3 Authority and applicability of this part.

BOEM authorizes you to conduct exploration or scientific research
activities under this part in accordance with the Act, the regulations
in this part, orders of the Director/Regional Director, and other
applicable statutes, regulations, and amendments.
(a) This part does not apply to G&G exploration conducted by or on
behalf of the lessee on a lease in the OCS. Refer to 30 CFR part 250 if
you plan to conduct G&G activities related to oil, gas, or sulphur under
terms of a lease.
(b) Federal agencies are exempt from the regulations in this part.
(c) G&G exploration or G&G scientific research related to minerals
other than oil, gas, and sulphur is covered by regulations at 30 CFR
part 580.

Sec. 551.4 Types of G&G activities that require permits or Notices.

(a) Exploration. You must have a BOEM-approved permit to conduct G&G
exploration, including deep stratigraphic tests, for oil, gas, or
sulphur resources. If you conduct both geological and geophysical
exploration, you must have a separate permit for each.
(b) Scientific research. You may only conduct G&G scientific
research related to oil, gas, and sulphur in the OCS after you obtain a
BOEM-approved permit or file a Notice.
(1) Permit. You must obtain a permit if the research activities you
propose to conduct involve:
(i) Using solid or liquid explosives;
(ii) Drilling a deep stratigraphic test; or
(iii) Developing data and information for proprietary use or sale.
(2) Notice. Any other G&G scientific research that you conduct
related to oil, gas, and sulphur in the OCS requires you to file a
Notice with the Regional Director at least 30 days before you begin. If
circumstances preclude a 30-day Notice, you must provide oral
notification and followup in writing. You must also inform BOEM in
writing when you conclude your work.

[[Page 419]]

Sec. 551.5 Applying for permits or filing Notices.

(a) Permits. You must submit a signed original and three copies of
the BOEM permit application form (Form BOEM-0327). The form includes
names of persons; the type, location, purpose, and dates of activity;
and environmental and other information. A nonrefundable service fee of
$2,012 must be paid electronically through Pay.gov at: https://
www.pay.gov/paygov/, and you must include a copy of the Pay.gov
confirmation receipt page with your application.
(b) Disapproval of permit application. If BOEM disapproves your
application for a permit, the Regional Director will state the reasons
for the denial and will advise you of the changes needed to obtain
approval.
(c) Notices. You must sign and date a Notice and state:
(1) The name(s) of the person(s) who will conduct the proposed
research;
(2) The name(s) of any other person(s) participating in the proposed
research, including the sponsor;
(3) The type of research and a brief description of how you will
conduct it;
(4) The location in the OCS, indicated on a map, plat, or chart,
where you will conduct research;
(5) The proposed dates you project for your research activity to
start and end;
(6) The name, registry number, registered owner, and port of
registry of vessels used in the operation;
(7) The earliest practicable time you expect to make the data and
information resulting from your research activity available to the
public;
(8) Your plan of how you will make the data and information you
collected available to the public;
(9) That you and others involved will not sell or withhold for
exclusive use the data and information resulting from your research; and
(10) At your option, you may submit (as a substitute for the
material required in paragraphs (c)(7), (c)(8), and (c)(9) of this
section) the nonexclusive use agreement for scientific research
attachment to Form BOEM-0327.
(d) Filing locations. You must apply for a permit or file a Notice
at one of the following locations:
(1) For the OCS off the State of Alaska--the Regional Supervisor for
Resource Evaluation, Bureau of Ocean Energy Management, Alaska OCS
Region, 3801 Centerpoint Drive, Suite 500, Anchorage, Alaska 99503.
(2) For the OCS off the Atlantic Coast and in the Gulf of Mexico--
the Regional Supervisor for Resource Evaluation, Bureau of Ocean Energy
Management, Gulf of Mexico OCS Region, 1201 Elmwood Park Boulevard, New
Orleans, Louisiana 70123-2394.
(3) For the OCS off the coast of the States of California, Oregon,
Washington, or Hawaii--the Regional Supervisor for Resource Evaluation,
Bureau of Ocean Energy Management, Pacific OCS Region, 760 Paseo
Camarillo, Suite 102 (CM 102), Camarillo, California 93010.

[76 FR 64623, Oct. 18, 2011, as amended at 80 FR 57096, Sept. 22, 2015]

Sec. 551.6 Obligations and rights under a permit or a Notice.

While conducting G&G exploration or scientific research activities
under BOEM permit or Notice:
(a) You must not:
(1) Interfere with or endanger operations under any lease, right-of-
way, easement, right-of-use, Notice, or permit issued or maintained
under the Act;
(2) Cause harm or damage to life (including fish and other aquatic
life), property, or to the marine, coastal, or human environment;
(3) Cause harm or damage to any mineral resource (in areas leased or
not leased);
(4) Cause pollution;
(5) Disturb archaeological resources;
(6) Create hazardous or unsafe conditions; or
(7) Unreasonably interfere with or cause harm to other uses of the
area.
(b) You must immediately report to the Regional Director if you:
(1) Detect hydrocarbon occurrences;
(2) Detect environmental hazards which imminently threaten life and
property; or
(3) Adversely affect the environment, aquatic life, archaeological
resources, or other uses of the area where you are conducting
exploration or scientific research activities.

[[Page 420]]

(c) You must also consult and coordinate your G&G activities with
other users of the area for navigation and safety purposes.
(d) Any persons conducting shallow test drilling or deep
stratigraphic test drilling activities under a permit must use the best
available and safest technologies that the Regional Director determines
to be economically feasible.
(e) You may not claim any oil, gas, sulphur, or other minerals you
discover while conducting operations under a permit or Notice.

Sec. 551.7 Test drilling activities under a permit.

(a) Shallow test drilling. Before you begin shallow test drilling
under a permit, the Regional Director may require you to:
(1) Gather and submit seismic, bathymetric, sidescan sonar,
magnetometer, or other geophysical data and information to determine
shallow structural detail across and in the vicinity of the proposed
test.
(2) Submit information for coastal zone consistency certification
according to paragraphs (b)(3) and (4) of this section, and for
protecting archaeological resources according to paragraph (b)(5) of
this section.
(3) Allow all interested parties the opportunity to participate in
the shallow test according to paragraph (c) of this section, and meet
bonding requirements according to paragraph (d) of this section.
(b) Deep stratigraphic tests. You must submit to the appropriate
BOEM or BSEE Regional Director, at the address in Sec. 551.7(d), a
drilling plan (submitted to BOEM), an environmental report (submitted to
BOEM), an Application for Permit to Drill (Form BSEE-0123) (submitted to
BSEE), and a Supplemental APD Information Sheet (Form BSEE-0123S)
(submitted to BSEE) as follows:
(1) Drilling plan. The drilling plan must include:
(i) The proposed type, sequence, and timetable of drilling
activities;
(ii) A description of your drilling rig, indicating the important
features with special attention to safety, pollution prevention, oil-
spill containment and cleanup plans, and onshore disposal procedures;
(iii) The location of each deep stratigraphic test you will conduct,
including the location of the surface and projected bottomhole of the
borehole;
(iv) The types of geological and geophysical survey instruments you
will use before and during drilling;
(v) Seismic, bathymetric, sidescan sonar, magnetometer, or other
geophysical data and information sufficient to evaluate seafloor
characteristics, shallow geologic hazards, and structural detail across
and in the vicinity of the proposed test to the total depth of the
proposed test well; and
(vi) Other relevant data and information that the BOEM Regional
Director requires.
(2) Environmental report. The environmental report must include all
of the following material:
(i) A summary with data and information available at the time you
submitted the related drilling plan. BOEM will consider site-specific
data and information developed since the most recent environmental
impact statement or other environmental impact analysis in the immediate
area. The summary must meet the following requirements:
(A) You must concentrate on the issues specific to the site(s) of
drilling activity. However, you only need to summarize data and
information discussed in any environmental reports, analyses, or impact
statements prepared for the geographic area of the drilling activity.
(B) You must list referenced material. Include brief descriptions
and a statement of where the material is available for inspection.
(C) You must refer only to data that are available to BOEM.
(ii) Details about your project such as:
(A) A list and description of new or unusual technologies;
(B) The location of travel routes for supplies and personnel;
(C) The kinds and approximate levels of energy sources;
(D) The environmental monitoring systems; and

[[Page 421]]

(E) Suitable maps and diagrams showing details of the proposed
project layout.
(iii) A description of the existing environment. For this section,
you must include the following information on the area:
(A) Geology;
(B) Physical oceanography;
(C) Other uses of the area;
(D) Flora and fauna;
(E) Existing environmental monitoring systems; and
(F) Other unusual or unique characteristics that may affect or be
affected by the drilling activities.
(iv) A description of the probable impacts of the proposed action on
the environment and the measures you propose for mitigating these
impacts.
(v) A description of any unavoidable or irreversible adverse effects
on the environment that could occur.
(vi) Other relevant data that the BOEM Regional Director requires.
(3) Copies for coastal States. You must submit copies of the
drilling plan and environmental report to the BOEM Regional Director for
transmittal to the Governor of each affected coastal State and the
coastal zone management agency of each affected coastal State that has
an approved program under the Coastal Zone Management Act. (BOEM
Regional Director will make the drilling plan and environmental report
available to appropriate Federal agencies and the public according to
the Department of the Interior's policies and procedures).
(4) Certification of coastal zone management program consistency and
State concurrence. When required under an approved coastal zone
management program of an affected State, your drilling plan must include
a certification that the proposed activities described in the plan
comply with enforceable policies of, and will be conducted in a manner
consistent with such State's program. BOEM Regional Director may not
approve any of the activities described in the drilling plan unless the
State concurs with the consistency certification or the Secretary of
Commerce makes the finding authorized by section 307(c)(3)(B)(iii) of
the Coastal Zone Management Act.
(5) Protecting archaeological resources. If the Regional Director
believes that an archaeological resource may exist in the area that may
be affected by drilling, the Regional Director will notify you of the
need to prepare an archaeological report.
(i) If the evidence suggests that an archaeological resource may be
present, you must:
(A) Locate the site of the drilling so as to not adversely affect
the area where the archaeological resources may be, or
(B) Establish to the satisfaction of the BOEM Regional Director that
an archaeological resource does not exist or will not be adversely
affected by drilling. This must be done by further archaeological
investigation, conducted by an archaeologist and a geophysicist, using
survey equipment and techniques deemed necessary by the Regional
Director. A report on the investigation must be submitted to the BOEM
Regional Director for review.
(ii) If the BOEM Regional Director determines that an archaeological
resource is likely to be present in the area that may be affected by
drilling, and may be adversely affected by drilling, the BOEM Regional
Director will notify you immediately. You must take no action that may
adversely affect the archaeological resource unless an investigation by
BOEM determines that the resource is not archaeologically significant.
(iii) If you discover any archaeological resource while drilling,
you must immediately halt drilling and report the discovery to the BOEM
Regional Director. If investigations determine that the resource is
significant, the BOEM Regional Director will inform you how to protect
it.
(6) [Reserved]
(7) Revising an approved drilling plan. Before you revise an
approved drilling plan, you must obtain the BOEM Regional Director's
approval.
(8) [Reserved]
(9) Deadline for completing a deep stratigraphic test. If your deep
stratigraphic test well is within 50 geographic miles of a tract that
BOEM has identified for a future lease sale, as listed on the currently
approved OCS leasing schedule,

[[Page 422]]

you must complete all drilling activities and submit the data and
information to the BOEM Regional Director at least 60 days before the
first day of the month in which BOEM schedules the lease sale. However,
the BOEM Regional Director may extend your permit duration to allow you
to complete drilling activities and submit data and information if the
extension is in the National interest.
(c) Group participation in test drilling. BOEM encourages group
participation for deep stratigraphic tests.
(1) Purpose of group participation. The purpose is to minimize
duplicative G&G activities involving drilling into the seabed of the
OCS.
(2) Providing opportunity for participation in a deep stratigraphic
test. When you propose to drill a deep stratigraphic test, you must give
all interested persons an opportunity to participate in the test
drilling through a signed agreement on a cost-sharing basis. You may
include a penalty for late participation of not more than 100 percent of
the cost to each original participant in addition to the original share
cost.
(i) The participants must assess and distribute late participation
penalties in accordance with the terms of the agreement.
(ii) For a significant hydrocarbon occurrence that the Regional
Director announces to the public, the penalty for subsequent late
participants may be raised to not more than 300 percent of the cost of
each original participant in addition to the original share cost.
(3) Providing opportunity for participation in a shallow test
drilling project. When you apply to conduct shallow test drilling
activities, you must, if ordered by the Regional Director or required by
the permit, give all interested persons an opportunity to participate in
the test activity on a cost-sharing basis. You may include a penalty
provision for late participation of not more than 50 percent of the cost
to each original participant in addition to the original share cost.
(4) Procedures for group participation in drilling activities. You
must:
(i) Publish a summary statement that describes the approved activity
in a relevant trade publication;
(ii) Forward a copy of the published statement to the Regional
Director;
(iii) Allow at least 30 days from the summary statement publication
date for other persons to join as original participants;
(iv) Compute the estimated cost by dividing the estimated total cost
of the program by the number of original participants; and
(v) Furnish the Regional Director with a complete list of all
participants before starting operations, or at the end of the
advertising period if you begin operations before the advertising period
is over. The names of any subsequent or late participants must also be
furnished to the Regional Director.
(5) Changes to the original application for test drilling. If you
propose changes to the original application and the Regional Director
determines that the changes are significant, the Regional Director will
require you to publish the changes for an additional 30 days to give
other persons a chance to join as original participants.
(d) Bonding requirements. You must submit a bond under this part
before you may start a deep stratigraphic test.
(1) Before BOEM issues a permit authorizing the drilling of a deep
stratigraphic test, you must either:
(i) Furnish to BOEM a bond of not less than $200,000 that guarantees
compliance with all the terms and conditions of the permit; or
(ii) Maintain a $1 million bond that guarantees compliance with all
the terms and conditions of the permit you hold for the OCS area where
you propose to drill.
(2) You must provide additional security to BOEM if the Regional
Director determines that it is necessary for the permit or area.
(3) The Regional Director may require you to provide a bond, in an
amount the Regional Director prescribes, before authorizing you to drill
a shallow test well.
(4) Your bond must be on a form approved by the Deputy Director.

[76 FR 64623, Oct. 18, 2011, as amended at 80 FR 57097, Sept. 22, 2015]

[[Page 423]]

Sec. 551.8 Inspection and reporting requirements for activities
under a permit.

(a) Inspection of permit activities. You must allow BOEM
representatives to inspect your exploration or scientific research
activities under a permit. They will determine whether operations are
adversely affecting the environment, aquatic life, archaeological
resources, or other uses of the area. BOEM will reimburse you for food,
quarters, and transportation that you provide for BOEM representatives
if you send in your reimbursement request to the Region that issued the
permit within 90 days of the inspection.
(b) Approval for modifications. Before you begin modified
operations, you must submit a written request describing the
modifications and receive the Regional Director's oral or written
approval. If circumstances preclude a written request, you must make an
oral request and follow up in writing.
(c) Reports. (1) You must submit status reports on a schedule
specified in the permit and include a daily log of operations.
(2) You must submit a final report of exploration or scientific
research activities under a permit within 30 days after the completion
of acquisition activities under the permit. You may combine the final
report with the last status report and must include each of the
following:
(i) A description of the work performed.
(ii) Charts, maps, plats, and digital navigational data in a format
specified by the Regional Director, showing the areas and blocks in
which any exploration or permitted scientific research activities were
conducted. Identify the lines of geophysical traverses and their
locations including a reference sufficient to identify the data produced
during each activity.
(iii) The dates on which you conducted the actual exploration or
scientific research activities.
(iv) A summary of any:
(A) Hydrocarbon or sulphur occurrences encountered;
(B) Environmental hazards; and
(C) Adverse effects of the exploration or scientific research
activities on the environment, aquatic life, archaeological resources,
or other uses of the area in which the activities were conducted.
(v) Other descriptions of the activities conducted as specified by
the Regional Director.

Sec. 551.9 Temporarily stopping, canceling, or relinquishing activities
approved under a permit.

(a) BOEM may temporarily stop exploration or scientific research
activities under a permit when the Regional Director determines that:
(1) Activities pose a threat of serious, irreparable, or immediate
harm. This includes damage to life (including fish and other aquatic
life), property, any mineral deposit (in areas leased or not leased), to
the marine, coastal, or human environment, or to an archaeological
resource;
(2) You failed to comply with any applicable law, regulation, order,
or provision of the permit. This would include BOEM's required
submission of reports, well records or logs, and G&G data and
information within the time specified; or
(3) Stopping the activities is in the interest of National security
or defense.
(b) Procedures to temporarily stop activities. (1) The Regional
Director will advise you either orally or in writing. BOEM will confirm
an oral notification in writing and deliver all written notifications by
courier or certified or registered mail. You must halt all activities
under a permit as soon as you receive an oral or written notification.
(2) The Regional Director will advise you when you may start your
permit activities again.
(c) Procedure to cancel or relinquish a permit. The Regional
Director may cancel, or a permittee may relinquish, a permit at any
time.
(1) If BOEM cancels your permit, the Regional Director will advise
you by certified or registered mail 30 days before the cancellation date
and will state the reason.
(2) You may relinquish the permit by advising the Regional Director
by certified or registered mail 30 days in advance.

[[Page 424]]

(3) After BOEM cancels your permit or you relinquish it, you are
still responsible for proper abandonment of any drill sites in
accordance with the requirements of 30 CFR 251.7(b)(8). You must also
comply with all other obligations specified in this part or in the
permit.

Sec. 551.10 Penalties and appeals.

(a) Penalties for noncompliance under a permit issued by BOEM. You
are subject to the penalty provisions of:
(1) Section 24 of the Act (43 U.S.C. 1350); and
(2) The procedures contained in 30 CFR part 550, subpart N, for
noncompliance with:
(i) Any provision of the Act;
(ii) Any provision of a G&G or drilling permit; or
(iii) Any regulation or order issued under the Act.
(b) Penalties under other laws and regulations. The penalties
prescribed in this section are in addition to any other penalty imposed
by any other law or regulation.
(c) Procedures to appeal orders or decisions BOEM issues. See 30 CFR
part 590 for instructions on how to appeal any order or decision that we
issue under this part.

Sec. 551.11 Submission, inspection, and selection of geological data
and information collected under a permit and processed by permittees
or third parties.

(a) Availability of geological data and information collected under
a permit. (1) You must notify the Regional Director, in writing, when
you complete the initial analysis, processing, or interpretation of any
geological data and information. Initial analysis and processing are the
stages of analysis or processing where the data and information first
become available for in-house interpretation by the permittee, or become
available commercially to third parties via sale, trade, license
agreement, or other means.
(2) The Regional Director may ask if you have further analyzed,
processed, or interpreted any geological data and information. When so
asked, you must respond to BOEM in writing within 30 days.
(b) Submission, inspection, and selection of geological data and
information. The Regional Director may request the permittee or third
party to submit the analyzed, processed, and interpreted geologic data
and information for inspection and/or permanent retention by BOEM. The
data and information must be submitted within 30 days after such
request.
(c) Requirements for submission of geological data and information
collected under a permit. Unless the Regional Director specifies
otherwise, geological data and information must include:
(1) An accurate and complete record of all geological (including
geochemical) data and information describing each operation of analysis,
processing, and interpretation;
(2) Paleontological reports identifying microscopic fossils by
depth, including the reference datum to which paleontological sample
depths are related and, if the Regional Director requests, washed
samples that you maintain for paleontological determinations;
(3) Copies of well logs or charts in a digital format, if available;
(4) Results and data obtained from formation fluid tests;
(5) Analyses of core or bottom samples and/or a representative cut
or split of the core or bottom sample;
(6) Detailed descriptions of any hydrocarbons or hazardous
conditions encountered during operations, including near losses of well
control, abnormal geopressures, and losses of circulation; and
(7) Other geological data and information that the Regional Director
may specify.
(d) Obligations when geological data and information collected under
permit are obtained by a third party. A third party may obtain
geological data and information from a permittee, or from another third
party, by sale, trade, license agreement, or other means. If this
happens:
(1) The third party recipient of the data and information assumes
the obligations under this section, except for the notification
provisions of paragraph (a)(1), and is subject to the penalty provisions
of 30 CFR part 550, subpart N; and

[[Page 425]]

(2) A permittee or third party that sells, trades, licenses, or
otherwise provides data and information to a third party must advise the
recipient, in writing, that accepting these obligations is a condition
precedent of the sale, trade, license, or other agreement; and
(3) Except for license agreements, a permittee or third party that
sells, trades, or otherwise provides data and information to a third
party must advise the Regional Director, in writing and within 30 days,
of the sale, trade, or other agreement, including the identity of the
recipient of the data and information; or
(4) For license agreements a permittee or third party that licenses
data and information to a third party must, within 30 days of a request
by the Regional Director, advise the Regional Director, in writing, of
the license agreement, including the identity of the recipient of the
data and information.

Sec. 551.12 Submission, inspection, and selection of geophysical data
and information collected under a permit and processed by permittees
or third parties.

(a) Availability of geophysical data and information collected under
a permit. (1) You must notify the Regional Director, in writing, when
you complete the initial processing and interpretation of any
geophysical data and information. Initial processing is the stage of
processing where the data and information become available for in-house
interpretation by the permittee, or become available commercially to
third parties via sale, trade, license agreement, or other means.
(2) The Regional Director may ask if you have further processed or
interpreted any geophysical data and information. When so asked, you
must respond to BOEM in writing within 30 days.
(b) Submission, inspection and selection of geophysical data and
information collected under a permit. The Regional Director may request
that the permittee or third party submit geophysical data and
information before making a final selection for retention. BOEM
representatives may inspect and select the data and information on your
premises, or the Regional Director can request delivery of the data and
information to the appropriate BOEM regional office for review.
(1) You must submit the geophysical data and information within 30
days of receiving the request, unless the Regional Director extends the
delivery time.
(2) At any time before final selection, the Regional Director may
return any or all geophysical data and information following review. You
will be notified in writing of all or portions of those data the
Regional Director decides to retain.
(c) Requirements for submission of geophysical data and information
collected under a permit. Unless the Regional Director specifies
otherwise, you must include:
(1) An accurate and complete record of each geophysical survey
conducted under the permit, including digital navigational data and
final location maps;
(2) All seismic data collected under a permit presented in a format
and of a quality suitable for processing;
(3) Processed geophysical information derived from seismic data with
extraneous signals and interference removed, presented in a quality
format suitable for interpretive evaluation, reflecting state-of-the-art
processing techniques; and
(4) Other geophysical data, processed geophysical information, and
interpreted geophysical information including, but not limited to,
shallow and deep subbottom profiles, bathymetry, sidescan sonar, gravity
and magnetic surveys, and special studies such as refraction and
velocity surveys.
(d) Obligations when geophysical data and information collected
under a permit are obtained by a third party. A third party may obtain
geophysical data, processed geophysical information, or interpreted
geophysical information from a permittee, or from another third party,
by sale, trade, license agreement, or other means. If this happens:
(1) The third party recipient of the data and information assumes
the obligations under this section, except for

[[Page 426]]

the notification provisions of paragraph (a)(1), and is subject to the
penalty provisions of 30 CFR part 550, subpart N; and
(2) A permittee or third party that sells, trades, licenses, or
otherwise provides data and information to a third party must advise the
recipient, in writing, that accepting these obligations is a condition
precedent of the sale, trade, license, or other agreement; and
(3) Except for license agreements, a permittee or third party that
sells, trades, or otherwise provides data and information to a third
party must advise the Regional Director, in writing and within 30 days,
of the sale, trade, or other agreement, including the identity of the
recipient of the data and information; or
(4) For license agreements, a permittee or third party that licenses
data and information to a third party must, within 30 days of a request
by the Regional Director, advise the Regional Director, in writing, of
the license agreement, including the identity of the recipient of the
data and information.

Sec. 551.13 Reimbursement for the costs of reproducing data and information
and certain processing costs.

(a) BOEM will reimburse you or a third party for reasonable costs of
reproducing data and information that the Regional Director requests if:
(1) You deliver G&G data and information to BOEM for the Regional
Director to inspect or select and retain (according to Sec. 551.11 or
Sec. 551.12);
(2) BOEM receives your request for reimbursement and the Regional
Director determines that the requested reimbursement is proper; and
(3) The cost is at your lowest rate (or a third party's) or at the
lowest commercial rate established in the area, whichever is less.
(b) BOEM will reimburse you or the third party for the reasonable
costs of processing geophysical information (which does not include cost
of data acquisition):
(1) If, at the request of the Regional Director, you processed the
geophysical data or information in a form or manner other than that used
in the normal conduct of business; or
(2) If you collected the information under a permit that BOEM issued
to you before October 1, 1985, and the Regional Director requests and
retains the information.
(c) When you request reimbursement, you must identify reproduction
and processing costs separately from acquisition costs.
(d) BOEM will not reimburse you or a third party for data
acquisition costs or for the costs of analyzing or processing geological
information or interpreting geological or geophysical information.

Sec. 551.14 Protecting and disclosing data and information submitted to BOEM
under a permit.

(a) Disclosure of data and information to the public by BOEM. (1) In
making data and information available to the public, the Regional
Director will follow the applicable requirements of:
(i) The Freedom of Information Act (5 U.S.C. 552);
(ii) The implementing regulations at 43 CFR part 2;
(iii) The Act; and
(iv) The regulations at 30 CFR parts 550 and 552.
(2) Except as specified in this section or in 30 CFR parts 550 and
552, if the Regional Director determines any data or information is
exempt from public disclosure under this paragraph (a), BOEM will not
provide the data and information to any State or to the executive of any
local government or to the public, unless you and all third parties
agree to the disclosure.
(3) BOEM will keep confidential the identity of third party
recipients of data and information collected under a permit. BOEM will
not release the identity unless you and the third parties agree to the
disclosure.
(4) When you detect any significant hydrocarbon occurrences or
environmental hazards on unleased lands during drilling operations, the
Regional Director will immediately issue a public announcement. The
announcement must further the National interest, but without unduly
damaging your competitive position.

[[Page 427]]

(b) Timetable for release of G&G data and information related to
oil, gas, and sulphur that BOEM acquires. Except for high-resolution
data and information released under 30 CFR 550.197(b)(2), BOEM will
release or disclose acquired data and information in accordance with
paragraphs (b)(1) through (7) of this section.
(1) If the data and information are not related to a deep
stratigraphic test, BOEM will release them to the public in accordance
with the following table:

------------------------------------------------------------------------
The Regional Director will
If you or a third party submit and BOEM release them to the public . .
retains . . . .
------------------------------------------------------------------------
(i) Geological data and information, 10 years after BOEM issued the
permit.
(ii) Geophysical data, 50 years after BOEM issued the
permit.
(iii) Geophysical information processed 25 years after BOEM issued the
or reprocessed less than 20 years permit.
after BOEM issued the germane permit,
(iv) Geophysical information processed 25 years after BOEM issued the
or reprocessed 20 or more years after permit; or, if you or a third
BOEM issued the germane permit, party applied for an extension
of the proprietary term, 5
years after BOEM approved the
application for an extension.
In any case BOEM will release
the information no later than
50 years after BOEM issued the
permit.
------------------------------------------------------------------------

(2) Permittees and third parties may apply to BOEM for an extension
of the 25-year proprietary term for geophysical information reprocessed
20 or more years after BOEM issued the germane permit. You must submit
the application to BOEM within 90 days after completion of the
reprocessing, except during the initial 1-year grace period as provided
in paragraph (b)(5) below. Filing locations are listed in Sec.
551.5(d). Your application must include:
(i) Name and address of the permittee or third party;
(ii) Product name;
(iii) Identification of the geophysical information area;
(iv) Identification of originating permit number and date;
(v) Description of reprocessing performed;
(vi) Identification of the date of completion of reprocessing the
geophysical information;
(vii) Certification that the product meets the definition of
processed geophysical information and that all other information in the
application is accurate; and
(viii) Signature and date.
(3) With each new reprocessing of permitted data, you may apply for
an extension of up to 5 years. However, the maximum proprietary term for
geophysical information is 50 years after the permit was issued. Once
the maximum term is reached, the BOEM Regional Director will release the
information to the public.
(4) Geophysical information processed or reprocessed 20 or more
years after the germane permit was issued and granted the extension will
be subject to submission, inspection, and selection criteria under Sec.
551.12 and reimbursement criteria identified under Sec. 551.13.
(5) There was a 1-year grace period, that started September 14,
2009, that allowed permittees and third parties sufficient time to meet
the above requirements and apply for all eligible extensions. During
that time, BOEM did not release geophysical information which was
reprocessed 20 or more years after the date that the germane permit was
issued.
(6) Since September 14, 2010, BOEM has resumed releasing eligible
reprocessed information. If an application for extension was not filed,
not filed on time, or not approved by BOEM, the original 25-year
proprietary term applies to the release date of the reprocessed
geophysical information.
(7) If the data and information are related to a deep stratigraphic
test, BOEM will release them to the public at the earlier of the
following times:
(i) Twenty-five years after you complete the test; or
(ii) If a lease sale is held after you complete a test well, 60-
calendar days after BOEM issues the first lease, any portion of which is
located within 50 geographic miles (92.7 kilometers) of the test.
(8) BOEM may allow limited inspection, but only by persons with a
direct

[[Page 428]]

interest in related BOEM decisions and issues in specific geographic
areas, and who agree in writing to its confidentiality, of G&G data and
information submitted under this part that BOEM uses to:
(i) Make unitization determinations on two or more leases;
(ii) Make competitive reservoir determinations;
(iii) Ensure proper plans of development for competitive reservoirs;
(iv) Promote operational safety;
(v) Protect the environment;
(vi) Make field determinations; or
(vii) Determine eligibility for royalty relief.
(c) Procedure that BOEM follows to disclose acquired data and
information to a contractor for reproduction, processing, and
interpretation. (1) When practical, the Regional Director will advise
the person who submitted data and information under Sec. 551.11 or
Sec. 551.12 of the intent to disclose the data or information to an
independent contractor or agent.
(2) The person so notified will have at least 5 working days to
comment on the action.
(3) When the Regional Director advises the person who submitted the
data and information, all other owners of the data or information will
be considered to have been so notified.
(4) Before disclosure, the contractor or agent must sign a written
commitment not to sell, trade, license, or disclose data or information
to anyone without the Regional Director's consent.
(d) Sharing data and information with coastal States. (1) When BOEM
solicits nominations for leasing lands located within 3 geographic miles
(5.6 kilometers) of the seaward boundary of any coastal State, the
Regional Director, in accordance with 30 CFR 552.7(a)(4) and (b) and
subsections 8(g) and 26(e) of the Act (43 U.S.C. 1337(g) and 1352(e)),
will provide the Governor with:
(i) All information on the geographical, geological, and ecological
characteristics of the areas and regions BOEM proposes to offer for
lease;
(ii) An estimate of the oil and gas reserves in the areas proposed
for leasing; and
(iii) An identification of any field, geological structure, or trap
on the OCS within 3 geographic miles (5.6 kilometers) of the seaward
boundary of the State.
(2) After receiving nominations for leasing an area of the OCS
within 3 geographic miles of the seaward boundary of any coastal State,
BOEM will carry out a tentative area identification according to 30 CFR
part 556, subparts D and E. At that time, the Regional Director will
consult with the Governor to determine whether any tracts further
considered for leasing may contain any oil or gas reservoirs that
underlie both the OCS and lands subject to the jurisdiction of the
State.
(3) Before a sale, if a Governor requests, the Regional Director, in
accordance with 30 CFR 552.7(a)(4) and (b) and sections 8(g) and 26(e)
of the Act (43 U.S.C. 1337(g) and 1352(e)), will share with the Governor
information that identifies potential and/or proven common hydrocarbon
bearing areas within 3 geographic miles of the seaward boundary of that
State.
(4) Information received and knowledge gained by a State official
under paragraph (d) of this section is subject to applicable
confidentiality requirements of:
(i) The Act; and
(ii) The regulations at 30 CFR parts 550, 551, and 552.

Sec. 551.15 Authority for information collection.

(a) The Office of Management and Budget has approved the information
collection requirements in this part under 44 U.S.C. 3501 et seq. and
assigned OMB control number 1010-0048. The title of this information
collection is ``30 CFR part 551, Geological and Geophysical (G&G)
Explorations of the OCS.''
(b) We may not conduct or sponsor, and you are not required to
respond to, a collection of information unless it displays a currently
valid OMB control number.
(c) We use the information collected under this part to:
(1) Evaluate permit applications and monitor scientific research
activities for environmental and safety reasons.

[[Page 429]]

(2) Determine that explorations do not harm resources, result in
pollution, create hazardous or unsafe conditions, or interfere with
other users in the area.
(3) Approve reimbursement of certain expenses.
(4) Monitor the progress and activities carried out under an OCS G&G
permit.
(5) Inspect and select G&G data and information collected under an
OCS G&G permit.
(d) Respondents are Federal OCS permittees and Notice filers.
Responses are mandatory or are required to obtain or retain a benefit.
We will protect information considered proprietary under applicable law
and under regulations at Sec. 551.14 and part 550 of this chapter.
(e) Send comments regarding any aspect of the collection of
information under this part, including suggestions for reducing the
burden, to the Information Collection Clearance Officer, Bureau of Ocean
Energy Management, 45600 Woodland Road, Sterling, VA 20166.

[76 FR 64623, Oct. 18, 2011, as amended at 80 FR 57097, Sept. 22, 2015]

PART 552_OUTER CONTINENTAL SHELF (OCS) OIL AND GAS INFORMATION PROGRAM--
Table of Contents

Sec.
552.1 Purpose.
552.2 Definitions.
552.3 Oil and gas data and information to be provided for use in the OCS
Oil and Gas Information Program.
552.4 Summary Report to affected States.
552.5 Information to be made available to affected States.
552.6 Freedom of Information Act requirements.
552.7 Privileged and proprietary data and information to be made
available to affected States.

Source: 76 FR 64623, Oct. 18, 2011, unless otherwise noted.

Sec. 552.1 Purpose.

The purpose of this part is to implement the provisions of section
26 of the Act (43 U.S.C. 1352). This part supplements the procedures and
requirements contained in 30 CFR parts 250, 251, 550, and 551 and
provides procedures and requirements for the submission of oil and gas
data and information resulting from exploration, development, and
production operations on the Outer Continental Shelf (OCS) to the
Director, Bureau of Ocean Energy Management. In addition, this part
establishes procedures for the Director to make available certain
information to the Governors of affected States and, upon request, to
the executives of affected local governments in accordance with the
provisions of the Freedom of Information Act and the Act.

Sec. 552.2 Definitions.

When used in the regulations in this part, the following terms shall
have the meanings given below:
Act refers to the Outer Continental Shelf Lands Act, as amended (43
U.S.C. 1331 et seq.).
Affected local government means the principal governing body of a
locality which is in an affected State and is identified by the Governor
of that State as a locality which will be significantly affected by oil
and gas activities on the OCS.
Affected State means, with respect to any program, plan, lease sale,
or other activity, proposed, conducted, or approved pursuant to the
provisions of the Act, any State:
(1) The laws of which are declared, pursuant to section 4(a)(2)(A)
of the Act, to be the law of the United States for the portion of the
OCS on which such activity is, or is proposed to be, conducted;
(2) Which is, or is proposed to be, directly connected by
transportation facilities to any artificial island or installations and
other devices permanently, or temporarily attached to the seabed;
(3) Which is receiving, or in accordance with the proposed activity
will receive, oil for processing, refining, or transshipment which was
extracted from the OCS and transported directly to such State by means
of vessels or by

[[Page 430]]

a combination of means including vessels;
(4) Which is designated by the Director as a State in which there is
a substantial probability of significant impact on or damage to the
coastal, marine, or human environment, or a State in which there will be
significant changes in the social, governmental, or economic
infrastructure, resulting from the exploration, development, and
production of oil and gas anywhere on the OCS; or
(5) In which the Director finds that because of such activity there
is, or will be, a significant risk of serious damage, due to factors
such as prevailing winds and currents, to the marine or coastal
environment in the event of any oilspill, blowout, or release of oil or
gas from vessels, pipelines, or other transshipment facilities.
Analyzed geological information means data collected under a permit
or a lease which have been analyzed. Analysis may include, but is not
limited to, identification of lithologic and fossil content, core
analyses, laboratory analyses of physical and chemical properties, logs
or charts of electrical, radioactive, sonic, and other well logs, and
descriptions of hydrocarbon shows or hazardous conditions.
Area adjacent to a State means all of that portion of the OCS
included within a planning area if such planning area is bordered by
that State. The portion of the OCS in the Navarin Basin Planning Area is
deemed to be adjacent to the State of Alaska. The States of New York and
Rhode Island are deemed to be adjacent to both the Mid-Atlantic Planning
Area and the North Atlantic Planning Area.
Data means facts and statistics or samples which have not been
analyzed or processed.
Development means those activities which take place following
discovery of oil or natural gas in paying quantities, including
geophysical activity, drilling, platform construction, and operation of
all onshore support facilities, and which are for the purpose of
ultimately producing the oil and gas discovered.
Director means the Director of the Bureau of Ocean Energy Management
of the U.S. Department of the Interior or a designee of the Director.
Exploration means the process of searching for oil and natural gas,
including:
(1) Geophysical surveys where magnetic, gravity, seismic, or other
systems are used to detect or imply the presence of such oil or natural
gas, and
(2) Any drilling, whether on or off known geological structures,
including the drilling of a well in which a discovery of oil or natural
gas in paying quantities is made and the drilling of any additional
delineation well after such discovery which is needed to delineate any
reservoir and to enable the lessee to determine whether to proceed with
development and production.
Governor means the Governor of a State, or the person or entity
designated by, or pursuant to, State law to exercise the powers granted
to a Governor pursuant to the Act.
Information, when used without a qualifying adjective, includes
analyzed geological information, processed geophysical information,
interpreted geological information, and interpreted geophysical
information.
Interpreted geological information means knowledge, often in the
form of schematic cross sections and maps, developed by determining the
geological significance of data and analyzed geological information.
Interpreted geophysical information means knowledge, often in the
form of schematic cross sections and maps, developed by determining the
geological significance of geophysical data and processed geophysical
information.
Lease means any form of authorization which is issued under section
8 or maintained under section 6 of the Act and which authorizes
exploration for, and development and production of, oil or natural gas,
or the land covered by such authorization, whichever is required by the
context.
Lessee means the party authorized by a lease, or an approved
assignment thereof, to explore for and develop and produce the leased
deposits in accordance with the regulations in part 550 of this chapter,
including all parties holding such authority by or through the lessee.

[[Page 431]]

Outer Continental Shelf (OCS) means all submerged lands which lie
seaward and outside of the area of lands beneath navigable waters as
defined in the Submerged Lands Act (67 Stat. 29) and of which the
subsoil and seabed appertain to the United States and are subject to its
jurisdiction and control.
Permittee means the party authorized by a permit issued pursuant to
part 551 of this chapter to conduct activities on the OCS.
Processed geophysical information means data collected under a
permit or a lease which have been processed. Processing involves
changing the form of data so as to facilitate interpretation. Processing
operations may include, but are not limited to, applying corrections for
known perturbing causes, rearranging or filtering data, and combining or
transforming data elements.
Production means those activities which take place after the
successful completion of any means for the removal of oil or natural
gas, including such removal, field operations, transfer of oil or
natural gas to shore, operation monitoring, maintenance, and workover
drilling.
Secretary means the Secretary of the Interior or a designee of the
Secretary.

Sec. 552.3 Oil and gas data and information to be provided for use
in the OCS Oil and Gas Information Program.

[[Page 432]]

contractor or agent, all other owners of such data or information shall
be deemed to have been notified of the Director's intent. Prior to any
such disclosure, the contractor or agent shall be required to execute a
written commitment not to disclose any data or information to anyone
without the express consent of the Director, and not to make any
disclosure or use of the data or information other than that provided in
the contract. Contracts between BOEM and independent contractors shall
be available to the lessee(s) or permittee(s) for inspection. In the
event of any unauthorized use or disclosure of data or information by
the contractor or agent, or by an employee thereof, the responsible
contractor or agent or employee thereof shall be liable for penalties
pursuant to section 24 of the Act.
(e)(1) After delivery of data or information in accordance with
paragraph (b)(1) of this section and upon receipt of a request for
reimbursement and a determination by the Director that the requested
reimbursement is proper, the lessee or permittee shall be reimbursed for
the cost of reproducing the data or information at the lessee's or
permittee's lowest rate or at the lowest commercial rate established in
the area, whichever is less. Requests for reimbursement must be made
within 60 days of the delivery date of the data or information requested
under paragraph (b)(1) of this section.
(2) After delivery of data or information in accordance with
paragraph (b)(3) of this section, and upon receipt of a request for
reimbursement and a determination by the Director that the requested
reimbursement is proper, the lessee or permittee shall be reimbursed for
the cost of processing or reprocessing and of reproducing the requested
data or information. Requests for reimbursement must be made within 60
days of the delivery date of the data or information and shall be for
only the costs attributable to processing or reprocessing and
reproducing, as distinguished from the costs of data acquisition.
(3) Requests for reimbursement are to contain a breakdown of costs
in sufficient detail to allow separation of reproduction, processing,
and reprocessing costs from acquisition and other costs.
(f) Each Federal Department or Agency shall provide the Director
with any data which it has obtained pursuant to section 11 of the Act
and any other information which may be necessary or useful to assist the
Director in carrying out the provisions of the Act.

Sec. 552.4 Summary Report to affected States.

(a) The Director, as soon as practicable after analysis,
interpretation, and compilation of oil and gas data and information
developed by BOEM or furnished by lessees, permittees, or other
government agencies, shall make available to affected States and, upon
request, to the executive of any affected local government, a Summary
Report of data and information designed to assist them in planning for
the onshore impacts of potential OCS oil and gas development and
production. The Director shall consult with affected States and other
interested parties to define the nature, scope, content, and timing of
the Summary Report. The Director may consult with affected States and
other interested parties regarding subsequent revisions in the
definition of the nature, scope, content, and timing of the Summary
Report. The Summary Report shall not contain data or information which
the Director determines is exempt from disclosure in accordance with
this part. The Summary Report shall not contain data or information the
release of which the Director determines would unduly damage the
competitive position of the lessee or permittee who provided the data or
information which the Director has processed, analyzed, or interpreted
during the development of the Summary Report. The Summary Report shall
include:
(1) Estimates of oil and gas reserves; estimates of the oil and gas
resources that may be found within areas which the Secretary has leased
or plans to offer for lease; and when available, projected rates and
volumes of oil and gas to be produced from leased areas;
(2) Magnitude of the approximate projections and timing of
development,

[[Page 433]]

if and when oil or gas, or both, is discovered;
(3) Methods of transportation to be used, including vessels and
pipelines and approximate location of routes to be followed; and
(4) General location and nature of near-shore and onshore facilities
expected to be utilized.
(b) When the Director determines that significant changes have
occurred in the information contained in a Summary Report, the Director
shall prepare and make available the new or revised information to each
affected State, and, upon request, to the executive of any affected
local government.

Sec. 552.5 Information to be made available to affected States.

(a) The Director shall prepare an index of OCS information (see 30
CFR 556.10). The index shall list all relevant actual or proposed
programs, plans, reports, environmental impact statements, nominations
information, environmental study reports, lease sale information, and
any similar type of relevant information, including modifications,
comments, and revisions prepared or directly obtained by the Director
under the Act. The index shall be sent to affected States and, upon
request, to any affected local government. The public shall be informed
of the availability of the index.
(b) Upon request, the Director shall transmit to affected States,
affected local governments, and the public a copy of any information
listed in the index which is subject to the control of BOEM, in
accordance with the requirements and subject to the limitations of the
Freedom of Information Act (5 U.S.C. 552) and implementing regulations.
The Director shall not transmit or make available any information which
he determines is exempt from disclosure in accordance with this part.

Sec. 552.6 Freedom of Information Act requirements.

(a) The Director shall make data and information available in
accordance with the requirements and subject to the limitations of the
Freedom of Information Act (5 U.S.C. 552), the regulations contained in
43 CFR part 2 (Records and Testimony), the requirements of the Act, and
the regulations contained in 30 CFR parts 250 and 550 (Oil and Gas and
Sulphur Operations in the Outer Continental Shelf) and 30 CFR part 551
(Geological and Geophysical Explorations of the Outer Continental
Shelf).
(b) Except as provided in Sec. 552.7 or in 30 CFR parts 250, 251,
550, and 551 of this chapter, no data or information determined by the
director to be exempt from public disclosure under paragraph (a) of this
section shall be provided to any affected State or be made available to
the executive of any affected local government or to the public unless
the lessee, or the permittee and all persons to whom such permittee has
sold such data or information under promise of confidentiality, agree to
such action.

Sec. 552.7 Privileged and proprietary data and information
to be made available to affected States.

(a)(1) The Governor of any affected State may designate an
appropriate State official to inspect, at a regional location which the
Director shall designate, any privileged or proprietary data or
information received by the Director regarding any activity in an area
adjacent to such State, except that no such inspection shall take place
prior to the sale of a lease covering the area in which such activity
was conducted.
(2)(i) Except as provided for in 30 CFR 250.197, 550.197, and
551.14, no privileged or proprietary data or information will be
transmitted to any affected State unless the lessee who provided the
privileged or proprietary data or information agrees in writing to the
transmittal of the data or information.
(ii) Except as provided for in 30 CFR 250.197, 550.197, and 551.14,
no privileged or proprietary data or information will be transmitted to
any affected State unless the permittee and all persons to whom the
permittee has sold the data or information under promise of
confidentiality agree in writing to the transmittal of the data or
information.
(3) Knowledge obtained by a State official who inspects data or
information under paragraph (a)(1) of this section or who receives data
or information under paragraph (a)(2) of this section

[[Page 434]]

shall be subject to the requirements and limitations of the Freedom of
Information Act (5 U.S.C. 552), the regulations contained in 43 CFR part
2 (Records and Testimony), the Act (92 Stat. 629), the regulations
contained in 30 CFR parts 250 and 550 (Oil and Gas and Sulphur
Operations in the Outer Continental Shelf), the regulations contained in
30 CFR parts 251 and 551 (Geological and Geophysical Explorations of the
Outer Continental Shelf), and the regulations contained in 30 CFR parts
252 and 552 (Outer Continental Shelf Oil and Gas Information Program).
(4) Prior to the transmittal of any privileged or proprietary data
or information to any State, or the grant of access to a State official
to such data or information, the Secretary shall enter into a written
agreement with the Governor of the State in accordance with section
26(e) of the Act (43 U.S.C. 1352). In that agreement the State shall
agree, as a condition precedent to receiving or being granted access to
such data or information to:
(i) Protect and maintain the confidentiality of privileged or
proprietary data and information in accordance with the laws and
regulations listed in paragraph (a)(3) of this section;
(ii) Waive the defenses as set forth in paragraph (b)(2) of this
section; and
(iii) Hold the United States harmless from any violations of the
agreement to protect the confidentiality of privileged or proprietary
data or information by the State or its employees or contractors.
(b)(1) Whenever any employee of the Federal Government or of any
State reveals in violation of the Act or of the provisions of the
regulations implementing the Act, privileged or proprietary data or
information obtained pursuant to the regulations in this chapter, the
lessee or permittee who supplied such information to the Director or any
other Federal official, and any person to whom such lessee or permittee
has sold such data or information under the promise of confidentiality,
may commence a civil action for damages in the appropriate district
court of the United States against the Federal Government or such State,
as the case may be. Any Federal or State employee who is found guilty of
failure to comply with any of the requirements of this section shall be
subject to the penalties described in section 24 of the Act (43 U.S.C.
1350).
(2) In any action commenced against the Federal Government or a
State pursuant to paragraph (b)(1) of this section, the Federal
Government or such State, as the case may be, may not raise as a defense
any claim of sovereign immunity, or any claim that the employee who
revealed the privileged or proprietary data or information which is the
basis of such suit was acting outside the scope of the person's
employment in revealing such data or information.
(c) If the Director finds that any State cannot or does not comply
with the conditions described in the agreement entered into pursuant to
paragraph (a)(4) of this section, the Director shall thereafter withhold
transmittal and deny access for inspection of privileged or proprietary
data or information to such State until the Director finds that such
State can and will comply with those conditions.

PART 553_OIL SPILL FINANCIAL RESPONSIBILITY FOR OFFSHORE FACILITIES--
Table of Contents

Subpart A_General

Sec.
553.1 What is the purpose of this part?
553.3 How are the terms used in this regulation defined?
553.5 What is the authority for collecting Oil Spill Financial
Responsibility (OSFR) information?

Subpart B_Applicability and Amount of OSFR

553.10 What facilities does this part cover?
553.11 Who must demonstrate OSFR?
553.12 May I ask BOEM for a determination of whether I must demonstrate
OSFR?
553.13 How much OSFR must I demonstrate?
553.14 How do I determine the worst case oil-spill discharge volume?
553.15 What are my general OSFR compliance responsibilities?

[[Page 435]]

Subpart C_Methods for Demonstrating OSFR

553.20 What methods may I use to demonstrate OSFR?
553.21 How can I use self-insurance as OSFR evidence?
553.22 How do I apply to use self-insurance as OSFR evidence?
553.23 What information must I submit to support my net worth
demonstration?
553.24 When I submit audited annual financial statements to verify my
net worth, what standards must they meet?
553.25 What financial test procedures must I use to determine the amount
of self-insurance allowed as OSFR evidence based on net worth?
553.26 What information must I submit to support my unencumbered assets
demonstration?
553.27 When I submit audited annual financial statements to verify my
unencumbered assets, what standards must they meet?
553.28 What financial test procedures must I use to evaluate the amount
of self-insurance allowed as OSFR evidence based on
unencumbered assets?
553.29 How can I use insurance as OSFR evidence?
553.30 How can I use an indemnity as OSFR evidence?
553.31 How can I use a surety bond as OSFR evidence?
553.32 Are there alternative methods to demonstrate OSFR?

Subpart D_Requirements for Submitting OSFR Information

553.40 What OSFR evidence must I submit to BOEM?
553.41 What terms must I include in my OSFR evidence?
553.42 How can I amend my list of COFs?
553.43 When is my OSFR demonstration or the amendment to my OSFR
demonstration effective?
553.44 [Reserved]
553.45 Where do I send my OSFR evidence?

Subpart E_Revocation and Penalties

553.50 How can BOEM refuse or invalidate my OSFR evidence?
553.51 What are the penalties for not complying with this part?

Subpart F_Claims for Oil-Spill Removal Costs and Damages

553.60 To whom may I present a claim?
553.61 When is a guarantor subject to direct action for claims?
553.62 What are the designated applicant's notification obligations
regarding a claim?

Subpart G_Limit of Liability for Offshore Facilities

553.700 What is the scope of this subpart?
553.701 To which entities does this subpart apply?
553.702 What limit of liability applies to my offshore facility?
553.703 What is the procedure for calculating the limit of liability
adjustment for inflation?
553.704 How will BOEM publish the offshore facility limit of liability
adjustment?

Appendix to Part 553--List of U.S. Geological Survey Topographic Maps

Authority: 33 U.S.C. 2704, 2716; E.O. 12777, as amended.

Source: 76 FR 64623, Oct. 18, 2011, unless otherwise noted.

Subpart A_General

Sec. 553.1 What is the purpose of this part?

This part establishes the requirements for demonstrating Oil Spill
Financial Responsibility for covered offshore facilities (COF), sets
forth the procedures for claims against COF guarantors, and sets forth
the limit of liability for offshore facilities, as adjusted, un der
Title I of the Oil Pollution Act of 1990, as amended, 33 U.S.C. 2701 et
seq. (OPA).

[79 FR 73839, Dec. 12, 2014]

Sec. 553.3 How are the terms used in this regulation defined?

Terms used in this part have the following meaning:
Advertise means publication of the notice of designation of the
source of the incident and the procedures by which the claims may be
presented, according to 33 CFR part 136, subpart D.
Annual CPI-U means the annual ``Consumer Price Index-All Urban
Consumers, Not Seasonally Adjusted, U.S. City Average, All items, 1982 -
84 = 100,'' published by the U.S. Department of Labor, Bureau of Labor
Statistics.
Bay means a body of water included in the Geographic Names
Information System (GNIS) bay feature class. A GNIS bay includes an arm,
bay, bight, cove, estuary, gulf, inlet, or sound.

[[Page 436]]

Claim means a written request, for a specific sum, for compensation
for damages or removal costs resulting from an oil-spill discharge or a
substantial threat of the discharge of oil.
Claimant means any person or government who presents a claim for
compensation under OPA.
Coastline means the line of ordinary low water along that portion of
the coast that is in direct contact with the open sea which marks the
seaward limit of inland waters.
Covered offshore facility (COF) means a facility:
(1) That includes any structure and all its components (including
wells completed at the structure and the associated pipelines),
equipment, pipeline, or device (other than a vessel or other than a
pipeline or deepwater port licensed under the Deepwater Port Act of 1974
(33 U.S.C. 1501 et seq.)) used for exploring for, drilling for, or
producing oil or for transporting oil from such facilities. This
includes a well drilled from a mobile offshore drilling unit (MODU) and
the associated riser and well control equipment from the moment a drill
shaft or other device first touches the seabed for purposes of exploring
for, drilling for, or producing oil, but it does not include the MODU;
and
(2) That is located:
(i) Seaward of the coastline; or
(ii) In any portion of a bay that is:
(A) Connected to the sea, either directly or through one or more
other bays; and
(B) Depicted in whole or in part on any USGS map listed in the
Appendix to this part, or on any map published by the USGS that is a
successor to and covers all or part of the same area as a listed map.
Where any portion of a bay is included on a listed map, this rule
applies to the entire bay; and
(3) That has a worst case oil-spill discharge potential of more than
1,000 bbls of oil, or a lesser volume if the Director determines in
writing that the oil-spill discharge risk justifies the requirement to
demonstrate OSFR.
Current period means the year in which the Annual CPI-U was most
recently published by the U.S. Department of Labor, Bureau of Labor
Statistics.
Designated applicant means a person the responsible parties
designate to demonstrate OSFR for a COF on a lease, permit, or right-of-
use and easement.
Director means the Director of the Bureau of Ocean Energy
Management.
Fund means the Oil Spill Liability Trust Fund established by section
9509 of the Internal Revenue Code of 1986 as amended (26 U.S.C. 9509).
Geographic Names Information System (GNIS) means the database
developed by the USGS in cooperation with the U.S. Board of Geographic
Names which contains the federally-recognized geographic names for all
known places, features, and areas in the United States that are
identified by a proper name. Each feature is located by state, county,
and geographic coordinates and is referenced to the appropriate
1:24,000-scale or 1:63,360-scale USGS topographic map on which it is
shown.
Guarantor means a person other than a responsible party who provides
OSFR evidence for a designated applicant.
Guaranty means any acceptable form of OSFR evidence provided by a
guarantor including an indemnity, insurance, or surety bond.
Incident means any occurrence or series of occurrences having the
same origin that results in the discharge or substantial threat of the
discharge of oil.
Indemnity means an agreement to indemnify a designated applicant
upon its satisfaction of a claim.
Indemnitor means a person providing an indemnity for a designated
applicant.
Independent accountant means a certified public accountant who is
certified by a state, or a chartered accountant certified by the
government of jurisdiction within the country of incorporation of the
company proposing to use one of the self-insurance evidence methods
specified in this subpart.
Insolvent has the meaning set forth in 11 U.S.C. 101, and generally
refers to a financial condition in which the sum of a person's debts is
greater than the value of the person's assets.
Lease means any form of authorization issued under the Outer
Continental Shelf Lands Act or state law

[[Page 437]]

which allows oil and gas exploration and production in the area covered
by the authorization.
Lessee means a person holding a leasehold interest in an oil or gas
lease including an owner of record title or a holder of operating rights
(working interest owner).
Oil means oil of any kind or in any form, except as excluded by
paragraph (2) of this definition.
(1) Oil includes:
(i) Petroleum, fuel oil, sludge, oil refuse, and oil mixed with
wastes other than dredged spoil;
(ii) Hydrocarbons produced at the wellhead in liquid form;
(iii) Gas condensate that has been separated from gas before
pipeline injection.
(2) Oil does not include petroleum, including crude oil or any
fraction thereof, which is specifically listed or designated as a
hazardous substance under subparagraphs (A) through (F) of section
101(14) of the Comprehensive Environmental Response, Compensation, and
Liability Act (CERCLA) (42 U.S.C. 9601).
Oil Spill Financial Responsibility (OSFR) means the capability and
means by which a responsible party for a covered offshore facility will
meet removal costs and damages for which it is liable under Title I of
the Oil Pollution Act of 1990, as amended (33 CFR 2701 et seq.), with
respect to both oil-spill discharges and substantial threats of the
discharge of oil.
Outer Continental Shelf (OCS) has the same meaning as the term
``Outer Continental Shelf'' defined in section 2(a) of the OCS Lands Act
(OCSLA) (43 U.S.C. 1331(a)).
Permit means an authorization, license, or permit for geological
exploration issued under section 11 of the OCSLA (43 U.S.C. 1340) or
applicable state law.
Person means an individual, corporation, partnership, association
(including a trust or limited liability company), state, municipality,
commission or political subdivision of a state, or any interstate body.
Pipeline means the pipeline segments and any associated equipment or
appurtenances used or intended for use in the transportation of oil or
natural gas.
Previous period means the year in which the previous limit of
liability was established, or last adjusted by statute or regulation,
whichever is later.
Responsible party, for purposes of subparts B through F, has the
following meanings:
(1) For a COF that is a pipeline, responsible party means any person
owning or operating the pipeline;
(2) For a COF that is not a pipeline, responsible party means either
the lessee or permittee of the area in which the COF is located, or the
holder of a right-of-use and easement granted under applicable State law
or the OCSLA (43 U.S.C. 1301-1356) for the area in which the COF is
located (if the holder is a different person than the lessee or
permittee). A Federal agency, State, municipality, commission, or
political subdivision of a State, or any interstate body that as owner
transfers possession and right to use the property to another person by
lease, assignment, or permit is not a responsible party; and
(3) For an abandoned COF, responsible party means any person who
would have been a responsible party for the COF immediately before
abandonment.
Responsible party, for purposes of subpart G, has the meaning in 33
U.S.C. 2701(32)(C), (E) and (F). This definition includes, as
applicable, lessees as defined in this subpart, permittees, right-of-use
and easement holders, and pipeline owners and operators.
Right-of-use and easement (RUE) means any authorization to use the
OCS or submerged land for purposes other than those authorized by a
lease or permit, as defined herein. It includes pipeline rights-of-way.
Source of the incident means the facility from which oil was
discharged or which poses a substantial threat of discharging oil, as
designated by the Director, National Pollution Funds Center, according
to 33 CFR part 136, subpart D.
State means the several States of the United States, the District of
Columbia, the Commonwealth of Puerto Rico, Guam, American Samoa, the
United

[[Page 438]]

States Virgin Islands, the Commonwealth of the Northern Marianas, and
any other territory or possession of the United States.

[76 FR 64623, Oct. 18, 2011, as amended at 79 FR 73839, Dec. 12, 2014]

Sec. 553.5 What is the authority for collecting
Oil Spill Financial Responsibility (OSFR) information?

(a) The Office of Management and Budget (OMB) has approved the
information collection requirements in this part 553 under 44 U.S.C.
3501 et seq., and assigned OMB control number 1010-0106.
(b) BOEM collects the information to ensure that the designated
applicant for a COF has the financial resources necessary to pay for
cleanup and damages that could be caused by oil discharges from the COF.
BOEM uses the information to ensure compliance of offshore lessees,
owners, and operators of covered facilities with OPA; to establish
eligibility of designated applicants for OSFR certification (OSFRC); and
to establish a reference source of names, addresses, and telephone
numbers of responsible parties for covered facilities and their
designated agents, guarantors, and U.S. agents for service of process
for claims associated with oil pollution from designated covered
facilities. The requirement to provide the information is mandatory. No
information submitted for OSFRC is confidential or proprietary.
(c) An agency may not conduct or sponsor, and a person is not
required to respond to, a collection of information unless it displays a
currently valid OMB control number.
(d) Send comments regarding any aspect of the collection of
information under this part, including suggestions for reducing the
burden, to the Information Collection Clearance Officer, Bureau of Ocean
Energy Management, 45600 Woodland Road, Sterling, VA 20166.

[76 FR 64623, Oct. 18, 2011, as amended at 80 FR 57097, Sept. 22, 2015]

Subpart B_Applicability and Amount of OSFR

Sec. 553.10 What facilities does this part cover?

(a) This part applies to any COF on any lease or permit issued or on
any RUE granted under the OCSLA or applicable State law.
(b) For a pipeline COF that extends onto land, this part applies to
that portion of the pipeline lying seaward of the first accessible flow
shut-off device on land.

Sec. 553.11 Who must demonstrate OSFR?

(a) A designated applicant must demonstrate OSFR. A designated
applicant may be a responsible party or another person authorized under
this section. Each COF must have a single designated applicant.
(1) If there is more than one responsible party, those responsible
parties must use Form BOEM-1017 to select a designated applicant. The
designated applicant must submit Form BOEM-1016 and agree to demonstrate
OSFR on behalf of all the responsible parties.
(2) If you are a designated applicant who is not a responsible
party, you must agree to be liable for claims made under OPA jointly and
severally with the responsible parties.
(b) The designated applicant for a COF on a lease must be either:
(1) A lessee; or
(2) The designated operator for the OCS lease under 30 CFR 550.143
or the unit operator designated under a Federally approved unit
including the OCS lease. For a lease or unit not in the OCS, the
operator designated under the lease or unit operating agreement for the
lease may be the designated applicant only if the operator has agreed to
be responsible for compliance with all the laws and regulations
applicable to the lease or unit.
(c) The designated applicant for a COF on a permit must be the
permittee.
(d) The designated applicant for a COF on a RUE must be the holder
of the RUE or, if there is a pipeline on the RUE, the owner or operator
of the pipeline.
(e) BOEM may require the designated applicant for a lease, permit,
or RUE to

[[Page 439]]

be a person other than a person identified in paragraphs (b) through (d)
of this section if BOEM determines that a person identified in
paragraphs (b) through (d) cannot adequately demonstrate OSFR.
(f) If you are a responsible party and you fail to designate an
applicant, then you must demonstrate OSFR under the requirements of this
part.

Sec. 553.12 May I ask BOEM for a determination of whether
I must demonstrate OSFR?

You may submit to BOEM a request for a determination of OSFR
applicability. Address the request to the office identified in Sec.
553.45. You must include in your request any information that will
assist BOEM in making the determination. BOEM may require you to submit
other information before making a determination of OSFR applicability.

Sec. 553.13 How much OSFR must I demonstrate?

(a) The following general parameters apply to the amount of OSFR
that you must demonstrate:

------------------------------------------------------------------------
If you are the designated applicant for . Then you must demonstrate .
. . . .
------------------------------------------------------------------------
Only one COF, The amount of OSFR that
applies to the COF.
More than one COF, The highest amount of OSFR
that applies to any one of
the COFs.
------------------------------------------------------------------------

(b) You must demonstrate OSFR in the amounts specified in this
section:
(1) For a COF located wholly or partially in the OCS you must
demonstrate OSFR in accordance with the following table:

------------------------------------------------------------------------
Applicable
COF worst case oil-spill discharge volume amount of OSFR
------------------------------------------------------------------------
Over 1,000 bbls but not more than 35,000 bbls........... $35,000,000
Over 35,000 but not more than 70,000 bbls............... 70,000,000
Over 70,000 but not more than 105,000 bbls.............. 105,000,000
Over 105,000 bbls....................................... 150,000,000
------------------------------------------------------------------------

(2) For a COF not located in the OCS you must demonstrate OSFR in
accordance with the following table:

------------------------------------------------------------------------
Applicable
COF worst case oil-spill discharge volume amount of OSFR
------------------------------------------------------------------------
Over 1,000 bbls but not more than 10,000 bbls........... $10,000,000
Over 10,000 but not more than 35,000 bbls............... 35,000,000
Over 35,000 but not more than 70,000 bbls............... 70,000,000
Over 70,000 but not more than 105,000 bbls.............. 105,000,000
Over 105,000 bbls....................................... 150,000,000
------------------------------------------------------------------------

(3) The Director may determine that you must demonstrate an amount
of OSFR greater than the amount in paragraphs (b)(1) and (2) of this
section based on the relative operational, environmental, human health,
and other risks that your COF poses. The Director may require an amount
that is one or more levels higher than the amount indicated in paragraph
(b)(1) or (2) of this section for your COF. The Director will not
require an OSFR demonstration that exceeds $150 million.
(4) You must demonstrate OSFR in the lowest amount specified in the
applicable table in paragraph (b)(1) or (2) of this section for a
facility with a potential worst case oil-spill discharge of 1,000 bbls
or less if the Director notifies you in writing that the demonstration

[[Page 440]]

is justified by the risks of the potential oil-spill discharge.

Sec. 553.14 How do I determine the worst case oil-spill discharge volume?

(a) To calculate the amount of OSFR you must demonstrate for a
facility under Sec. 553.13(b), you must use the worst case oil-spill
discharge volume that you determined under whichever of the following
regulations applies:
(1) 30 CFR part 254--Response Plans for Facilities Located Seaward
of the Coast Line, except that the volume of the worst case oil-spill
discharge for a well must be four times the uncontrolled flow volume
that you estimate for the first 24 hours.
(2) 40 CFR part 112--Oil Pollution Prevention; or
(3) 49 CFR part 194--Response Plans for Onshore Oil Pipelines.
(b) If you are a designated applicant and you choose to demonstrate
$150 million in OSFR, you are not required to determine any worst case
oil-spill discharge volumes, since that is the maximum amount of OSFR
required under this part.

Sec. 553.15 What are my general OSFR compliance responsibilities?

(a) You must maintain continuous OSFR coverage for all your leases,
permits, and RUEs with COFs for which you are the designated applicant.
(b) You must ensure that new OSFR evidence is submitted before your
current evidence lapses or is canceled and that coverage for your new
COF is submitted before the COF goes into operation.
(c) If you use self-insurance to demonstrate OSFR and find that you
no longer qualify to self-insure the required OSFR amount based upon
your latest audited annual financial statements, then you must
demonstrate OSFR using other methods acceptable to BOEM by whichever of
the following dates comes first:
(1) Sixty calendar days after you receive your latest audited annual
financial statement; or
(2) The first calendar day of the 5th month after the close of your
fiscal year.
(d) You may use a surety bond to demonstrate OSFR. If you find that
your bonding company has lost its state license or has had its U.S.
Treasury Department certification revoked, then you must replace the
surety bond within 15 calendar days using a method of OSFR that is
acceptable to BOEM.
(e) You must notify BOEM in writing within 15 calendar days after a
change occurs that would prevent you from meeting your OSFR obligations
(e.g., if you or your indemnitor petition for bankruptcy under chapters
7 or 11 of Title 11, U.S.C.). You must take any action BOEM directs to
ensure an acceptable OSFR demonstration.
(f) If you deny payment of a claim presented to you under Sec.
553.60, then you must give the claimant a written explanation for your
denial.

Subpart C_Methods for Demonstrating OSFR

Sec. 553.20 What methods may I use to demonstrate OSFR?

As the designated applicant, you may satisfy your OSFR requirements
by using one or a combination of the following methods to demonstrate
OSFR:
(a) Self-insurance under Sec. Sec. 553.21 through 553.28;
(b) Insurance under Sec. 553.29;
(c) An indemnity under Sec. 553.30;
(d) A surety bond under Sec. 553.31; or
(e) An alternative method the Director approves under Sec. 553.32.

Sec. 553.21 How can I use self-insurance as OSFR evidence?

(a) If you use self-insurance to satisfy all or part of your
obligation to demonstrate OSFR, you must annually pass either a net
worth test under Sec. 553.25 or an unencumbered net asset test under
Sec. 553.28.
(b) To establish the amount of self-insurance allowed, you must
submit evidence of your net worth under Sec. 553.23 or evidence of your
unencumbered assets under Sec. 553.26.
(c) You must identify a U.S. agent for service of process.

Sec. 553.22 How do I apply to use self-insurance as OSFR evidence?

(a) You must submit a complete Form BOEM-1018 with each application
to demonstrate OSFR using self-insurance.

[[Page 441]]

(b) You must submit your application to renew OSFR using self-
insurance by the first calendar day of the 5th month after the close of
your fiscal year. You may submit to BOEM your initial application to
demonstrate OSFR using self-insurance at any time.

Sec. 553.23 What information must I submit to support
my net worth demonstration?

You must support your net worth evaluation with information
contained in your previous fiscal year's audited annual financial
statement.
(a) Audited annual financial statements must be in the form of:
(1) An annual report, prepared in accordance with the generally
accepted accounting practices (GAAP) of the United States or other
international accounting practices determined to be equivalent by BOEM;
or
(2) A Form 10-K or Form 20-F, prepared in accordance with Securities
and Exchange Commission regulations.
(b) Audited annual financial statements must be submitted together
with a letter signed by your treasurer highlighting:
(1) The State or the country of incorporation;
(2) The total amount of the stockholders' equity as shown on the
balance sheet;
(3) The net amount of the plant, property, and equipment shown on
the balance sheet; and
(4) The net amount of the identifiable U.S. assets and the
identifiable total assets in the auditor's notes to the financial
statement (i.e., a geographic segmented business note).

Sec. 553.24 When I submit audited annual financial statements to verify
my net worth, what standards must they meet?

(a) Your audited annual financial statements must be bound.
(b) Your audited annual financial statements must include the
unqualified opinion of an independent accountant that states:
(1) The financial statements are free from material misstatement,
and
(2) The audit was conducted in accordance with the generally
accepted auditing standards (GAAS) of the United States, or other
international auditing standards that BOEM determines to be equivalent.
(c) The financial information you submit must be expressed in U.S.
dollars. If this information was originally reported in another form of
currency, you must convert it to U.S. dollars using the conversion
factor that was effective on the last day of the fiscal year pertinent
to your financial statements. You also must identify the source of the
currency exchange rate.

Sec. 553.25 What financial test procedures must I use to determine
the amount of self-insurance allowed as OSFR evidence based on net worth?

(a) Divide the total amount of the stockholders'/owners' equity
listed on the balance sheet by ten.
(b) Divide the net amount of the identifiable U.S. assets by the net
amount of the identifiable total assets.
(c) Multiply the net amount of plant, property, and equipment shown
on the balance sheet by the number calculated under paragraph (b) of
this section and divide the resultant product by ten.
(d) The smaller of the numbers calculated under paragraphs (a) or
(c) of this section is the maximum allowable amount you may use to
demonstrate OSFR under this method.

Sec. 553.26 What information must I submit to support my unencumbered
assets demonstration?

You must support your unencumbered assets evaluation with the
information required by Sec. 553.23(a) and a list of reserved,
unencumbered, and unimpaired U.S. assets whose value will not be
affected by an oil discharge from a COF. The assets must be plant,
property, or equipment held for use. You must submit a letter signed by
your treasurer:
(a) Identifying which assets are reserved;
(b) Certifying that the assets are unencumbered, including
contingent encumbrances;
(c) Promising that the identified assets will not be sold, subjected
to a security interest, or otherwise encumbered throughout the specified
fiscal year; and
(d) Specifying:
(1) The State or the country of incorporation;

[[Page 442]]

(2) The total amount of the stockholders'/owners' equity listed on
the balance sheet;
(3) The identification and location of the reserved U.S. assets; and
(4) The value of the reserved U.S. assets less accumulated
depreciation and amortization, using the same valuation method used in
your audited annual financial statement and expressed in U.S. dollars.
The net value of the reserved assets must be at least two times the
self-insurance amount requested for demonstration.

Sec. 553.27 When I submit audited annual financial statements to verify
my unencumbered assets, what standards must they meet?

Any audited annual financial statements that you submit must:
(a) Meet the standards in Sec. 553.24; and
(b) Include a certification by the independent accountant who
audited the financial statements that states:
(1) The value of the unencumbered assets is reasonable and uses the
same valuation method used in your audited annual financial statements;
(2) Any existing encumbrances are noted;
(3) The assets are long-term assets held for use; and
(4) The valuation method used in the audited annual financial
statements is for long-term assets held for use.

Sec. 553.28 What financial test procedures must I use to evaluate the amount
of self-insurance allowed as OSFR evidence based on unencumbered assets?

(a) Divide the total amount of the stockholders'/owners' equity
listed on the balance sheet by 4.
(b) Divide the value of the unencumbered U.S. assets by 2.
(c) The smaller number calculated under paragraphs (a) or (b) of
this section is the maximum allowable amount you may use to demonstrate
OSFR under this method.

Sec. 553.29 How can I use insurance as OSFR evidence?

(a) If you use insurance to satisfy all or part of your obligation
to demonstrate OSFR, you may use only insurance certificates issued by
insurers that have achieved a ``Secure'' rating for claims paying
ability in their latest review by A.M. Best's Insurance Reports,
Standard & Poor's Insurance Rating Services, or other equivalent rating
made by a rating service acceptable to BOEM.
(b) You must submit information about your insurers to BOEM on a
completed and unaltered Form BOEM-1019. The information you submit must:
(1) Include all the information required by Sec. 553.41 and
(2) Be executed on one original insurance certificate (i.e., Form
BOEM-1019) for each OSFR layer (see paragraph (c) of this section),
showing all participating insurers and their proportion (quota share) of
this risk. The certificate must bear the original signatures of each
insurer's underwriter or of their lead underwriters, underwriting
managers, or delegated brokers, depending on who is authorized to bind
the underwriter.
(3) For each insurance company on the insurance certificate,
indicate the insurer's claims-paying-ability rating and the rating
service that issued the rating.
(c) The insurance evidence you provide to BOEM as OSFR evidence may
be divided into layers, subject to the following restrictions:
(1) The total amount of OSFR evidence must equal the total amount
you must demonstrate under Sec. 553.13;
(2) No more than one insurance certificate may be used to cover each
OSFR layer specified in Sec. 553.13(b) (i.e., four layers for an OCS
COF, and five layers for a non-OCS COF);
(3) You may use one insurance certificate to cover any number of
consecutive OSFR layers;
(4) Each insurer's participation in the covered insurance risk must
be on a proportional (quota share) basis, must be expressed as a
percentage of a whole layer, and the certificate must not contain
intermediate, horizontal layers;
(5) You may use an insurance deductible. If you use more than one
insurance certificate, the deductible amount must apply only to the
certificate that covers the base OSFR amount layer. To satisfy an
insurance deductible, you may use only those methods that are

[[Page 443]]

acceptable as evidence of OSFR under this part; and
(6) You must identify a U.S. agent for service of process on each
insurance certificate you submit to BOEM. The agent may be different for
each insurance certificate.
(d) You may submit to BOEM a temporary insurance confirmation (fax
binder) for each insurance certificate you use as OSFR evidence. Submit
your fax binder on Form BOEM-1019, and each form must include the
signature of an underwriter for at least one of the participating
insurers. BOEM will accept your fax binder as OSFR evidence during a
period that ends 90 days after the date that you need the insurance to
demonstrate OSFR.

Sec. 553.30 How can I use an indemnity as OSFR evidence?

(a) You may use only one indemnity issued by only one indemnitor to
satisfy all or part of your obligation to demonstrate OSFR.
(b) Your indemnitor must be your corporate parent or affiliate.
(c) Your indemnitor must complete a Form BOEM-1018 and provide an
indemnity that:
(1) Includes all the information required by Sec. 553.41; and
(2) Does not exceed the amounts calculated using the net worth or
unencumbered assets tests specified under Sec. Sec. 553.21 through
553.28.
(d) You must submit your application to renew OSFR using an
indemnity by the first calendar day of the 5th month after the close of
your indemnitor's fiscal year. You may submit to BOEM your initial
application to demonstrate OSFR using an indemnity at any time.
(e) Your indemnitor must identify a U.S. agent for service of
process.

Sec. 553.31 How can I use a surety bond as OSFR evidence?

(a) Each bonding company that issues a surety bond that you submit
to BOEM as OSFR evidence must:
(1) Be licensed to do business in the State in which the surety bond
is executed;
(2) Be certified by the U.S. Treasury Department as an acceptable
surety for Federal obligations and listed in the current Treasury
Circular No. 570;
(3) Provide the surety bond on Form BOEM-1020; and
(4) Be in compliance with applicable statutes regulating surety
company participation in insurance-type risks.
(b) A surety bond that you submit as OSFR evidence must include all
the information required by Sec. 553.41.

Sec. 553.32 Are there alternative methods to demonstrate OSFR?

The Director may accept other methods to demonstrate OSFR that
provide equivalent assurance of timely satisfaction of claims. This may
include pooling, letters of credit, pledges of treasury notes, or other
comparable methods. Submit your proposal, together with all the
supporting documents, to the Director at the address listed in Sec.
553.45. The Director's decision whether to approve your alternative
method to evidence OSFR is by this rule committed to the Director's sole
discretion and is not subject to administrative appeal under 30 CFR part
590 or 43 CFR part 4.

Subpart D_Requirements for Submitting OSFR Information

Sec. 553.40 What OSFR evidence must I submit to BOEM?

(a) You must submit to BOEM:
(1) A single demonstration of OSFR that covers all the COFs for
which you are the designated applicant;
(2) A completed and unaltered Form BOEM-1016;
(3) BOEM forms that identify your COFs (Form BOEM-1021, Form BOEM-
1022), and the methods you will use to demonstrate OSFR (Form BOEM-1018,
Form BOEM-1019, Form BOEM-1020). Forms are available from the address
listed in Sec. 553.45;
(4) Any insurance certificates, indemnities, and surety bonds used
as OSFR evidence for the COFs for which you are the designated
applicant;
(5) A completed Form BOEM-1017 for each responsible party, unless
you are the only responsible party for the COFs covered by your OSFR
demonstration; and
(6) Other financial instruments and information the Director
requires to support your OSFR demonstration under Sec. 553.32.

[[Page 444]]

(b) Each BOEM form you submit to BOEM as part of your OSFR
demonstration must be signed. You also must attach to Form BOEM-1016
proof of your authority to sign.

Sec. 553.41 What terms must I include in my OSFR evidence?

(a) Each instrument you submit as OSFR evidence must specify:
(1) The effective date, and except for a surety bond, the expiration
date;
(2) That termination of the instrument will not affect the liability
of the instrument issuer for claims arising from an incident (i.e., oil-
spill discharge or substantial threat of the discharge of oil) that
occurred on or before the effective date of termination;
(3) That the instrument will remain in force until the termination
date or until the earlier of:
(i) Thirty calendar days after BOEM and the designated applicant
receive from the instrument issuer a notification of intent to cancel;
or
(ii) BOEM receives from the designated applicant other acceptable
OSFR evidence; or
(iii) All the COFs to which the instrument applies are permanently
abandoned in compliance with 30 CFR part 250 or equivalent State
requirements;
(4) That the instrument issuer agrees to direct action for claims
made under OPA up to the guaranty amount, subject to the defenses in
paragraph (a)(6) of this section and following the procedures in Sec.
553.60 of this part;
(5) An agent in the United States for service of process; and
(6) That the instrument issuer will not use any defenses against a
claim made under OPA except:
(i) The rights and defenses that would be available to a designated
applicant or responsible party for whom the guaranty was provided; and
(ii) The incident (i.e., oil-spill discharge or a substantial threat
of the discharge of oil) leading to the claim for removal costs or
damages was caused by willful misconduct of a responsible party for whom
the designated applicant demonstrated OSFR.
(b) You may not change, omit, or add limitations or exceptions to
the terms and conditions in a BOEM form that you submit as part of your
OSFR demonstration. If you attempt to do this, BOEM will disregard the
changes, omissions, additions, limitations, or exceptions and by
operation of this rule BOEM will consider the form to contain all the
terms and conditions included on the original BOEM form.

Sec. 553.42 How can I amend my list of COFs?

(a) If you want to add a COF that is not identified in your current
OSFR demonstration, you must submit to BOEM a completed Form BOEM-1022.
If applicable, you also must submit any additional indemnities, surety
bonds, insurance certificates, or other instruments required to extend
the coverage of your original OSFR demonstration to the COFs to be
added. You do not need to resubmit previously accepted audited annual
financial statements for the current fiscal year.
(b) If you want to drop a COF identified in your current OSFR
demonstration, you must submit to BOEM a completed Form BOEM-1022. You
must continue to demonstrate OSFR for the COF until BOEM approves OSFR
evidence for the COF from another designated applicant, or OSFR is no
longer required (e.g., until a well that is a COF is properly plugged
and abandoned).

Sec. 553.43 When is my OSFR demonstration or the amendment
to my OSFR demonstration effective?

(a) BOEM will notify you in writing when we approve your OSFR
demonstration. If we find that you have not submitted all the
information needed to demonstrate OSFR, we may require you to provide
additional information before we determine whether your OSFR evidence is
acceptable.
(b) Except in the case of self-insurance or an indemnity, BOEM
acceptance of OSFR evidence is valid until the surety bond, insurance
certificate, or other accepted OSFR instrument expires or is canceled.
In the case of self-insurance or indemnity, acceptance is valid until
the first day of the 5th month after the close of your or your
indemnitor's current fiscal year.

[[Page 445]]

Sec. 553.44 [Reserved]

Sec. 553.45 Where do I send my OSFR evidence?

Address all correspondence and required submissions related to this
part to: U.S. Department of the Interior, Bureau of Ocean Energy
Management, Gulf of Mexico Region, Oil Spill Financial Responsibility
Program, 1201 Elmwood Park Boulevard, New Orleans, Louisiana 70123.

Subpart E_Revocation and Penalties

Sec. 553.50 How can BOEM refuse or invalidate my OSFR evidence?

(a) If BOEM determines that any OSFR evidence you submit fails to
comply with the requirements of this part, we may not accept it. If we
do not accept your OSFR evidence, then we will send you a written
notification stating:
(1) That your evidence is not acceptable;
(2) Why your evidence is unacceptable; and
(3) The amount of time you are allowed to submit acceptable evidence
without being subject to civil penalty under Sec. 553.51.
(b) BOEM may immediately and without prior notice invalidate your
OSFR demonstration if you:
(1) Are no longer eligible to be the designated applicant for a COF
included in your demonstration; or
(2) Permit the cancellation or termination of the insurance policy,
surety bond, or indemnity upon which the continued validity of the
demonstration is based.
(c) If BOEM determines you are not complying with the requirements
of this part for any reason other than paragraph (b) of this section, we
will notify you of our intent to invalidate your OSFR demonstration and
specify the corrective action needed. Unless you take the corrective
action BOEM specifies within 15 calendar days from the date you receive
such a notice, we will invalidate your OSFR demonstration.

Sec. 553.51 What are the penalties for not complying with this part?

(a) If you fail to comply with the financial responsibility
requirements of OPA at 33 U.S.C. 2716 or with the requirements of this
part, then you may be liable for a civil penalty of up to $46,192 per
COF per day of violation (that is, each day a COF is operated without
acceptable evidence of OSFR).
(b) BOEM will determine the date of a noncompliance. BOEM will
assess penalties in accordance with an OSFR penalty schedule using the
procedures found at 30 CFR part 550, subpart N. You may obtain a copy of
the penalty schedule from BOEM at the address in Sec. 553.45.
(c) BOEM may assess a civil penalty against you that is greater or
less than the amount in the penalty schedule after taking into account
the factors in section 4303(a) of OPA (33 U.S.C. 2716a).
(d) If you fail to correct a deficiency in the OSFR evidence for a
COF, then the Director may suspend operation of a COF in the OCS under
30 CFR 250.170 or seek judicial relief, including an order suspending
the operation of any COF.

[76 FR 64623, Oct. 18, 2011, as amended at 81 FR 43069, July 1, 2016; 82
FR 10711, Feb. 15, 2017; 83 FR 8933, Mar. 2, 2018]

Subpart F_Claims for Oil-Spill Removal Costs and Damages

Sec. 553.60 To whom may I present a claim?

(a) If you are a claimant, you must present your claim first to the
designated applicant for the COF that is the source of the incident
resulting in your claim. If, however, the designated applicant has filed
a petition for bankruptcy under 11 U.S.C. chapter 7 or 11, you may
present your claim first to any of the designated applicant's
guarantors.
(b) If the claim you present to the designated applicant or
guarantor is denied or not paid within 90 days after you first present
it or advertising begins, whichever is later, then you may seek any of
the following remedies that apply:

[[Page 446]]

------------------------------------------------------------------------
If the reason for denial or nonpayment is
. . . Then you may elect to . . .
------------------------------------------------------------------------
(1) Not an assertion of insolvency or (i) Present your claim to
petition in bankruptcy under 11 U.S.C. any of the responsible
chapter 7 or 11, parties for the COF; or
(ii) Initiate a lawsuit
against the designated
applicant and/or any of the
responsible parties for the
COF; or
(iii) Present your claim to
the Fund using the
procedures at 33 CFR part
136.
(2) An assertion of insolvency or petition (i) Pursue any of the
in bankruptcy under 11 U.S.C. chapter 7 remedies in items (1)(i)
or 11, through (iii) of this
table; or
(ii) Present your claim to
any of the designated
applicant's guarantors; or
(iii) Initiate a lawsuit
against any of the
designated applicant's
guarantors.
------------------------------------------------------------------------

(c) If no one has resolved your claim to your satisfaction using the
remedy that you elected under paragraph (b) of this section, then you
may pursue another available remedy, unless the Fund has denied your
claim or a court of competent jurisdiction has ruled against your claim.
You may not pursue more than one remedy at a time.
(d) You may ask BOEM to assist you in determining whether a
guarantor may be liable for your claim. Send your request for assistance
to the address listed in Sec. 553.45. You must include any information
you have regarding the existence or identity of possible guarantors.

Sec. 553.61 When is a guarantor subject to direct action for claims?

(a) If you are a guarantor, then you are subject to direct action
for any claim asserted by:
(1) The United States for any compensation paid by the Fund under
OPA, including compensation claim processing costs; and
(2) A claimant other than the United States if the designated
applicant has:
(i) Denied or failed to pay a claim because of being insolvent; or
(ii) Filed a petition in bankruptcy under 11 U.S.C. chapters 7 or
11.
(b) If you participate in an insurance guaranty for a COF incident
(i.e., oil-spill discharge or substantial threat of the discharge of
oil) that is subject to claims under this part, then your maximum,
aggregate liability for those claims is equal to your quota share of the
insurance guaranty.

Sec. 553.62 What are the designated applicant's notification obligations
regarding a claim?

If you are a designated applicant, and you receive a claim for
removal costs and damages, then within 15 calendar days of receipt of a
claim you must notify:
(a) Your guarantors; and
(b) The responsible parties for whom you are acting as the
designated applicant.

Subpart G_Limit of Liability for Offshore Facilities

Source: 79 FR 73840, Dec. 12, 2014, unless otherwise noted.

Sec. 553.700 What is the scope of this subpart?

This subpart sets forth the limit of liability for damages for
offshore facilities under Title I of the Oil Pollution Act of 1990, as
amended (33 U.S.C. 2701 et seq.) (OPA), as adjusted, under section
1004(d) of OPA (33 U.S.C. 2704(d)). This subpart also sets forth the
method for adjusting the limit of liability for damages for offshore
facilities for inflation, by regulation, under section 1004(d) of OPA
(33 U.S.C. 2704(d)).

Sec. 553.701 To which entities does this subpart apply?

This subpart applies to you if you are a responsible party for an
offshore facility, other than a deepwater port under the Deepwater Port
Act of 1974 (33 U.S.C. 1501-1524), but including an offshore pipeline,
or an abandoned offshore facility, including any abandoned offshore
pipeline, unless your liability is unlimited under OPA 90 (33 U.S.C.
2704(c)).

[[Page 447]]

Sec. 553.702 What limit of liability applies to my offshore facility?

Except as provided in 33 U.S.C. 2704(c), the limit of liability
under OPA for a responsible party for any offshore facility, including
any offshore pipeline, is the total of all removal costs plus $137.6595
million for damages with respect to each incident.

[83 FR 2542, Jan. 18, 2018]

Sec. 553.703 What is the procedure for calculating the limit
of liability adjustment for inflation?

The procedure for calculating limit of liability adjustments for
inflation is as follows:
(a) Formula for calculating a cumulative percent change in the
Annual CPI-U. BOEM calculates the cumulative percent change in the
Annual CPI-U from the year the limit of liability was established by
statute, or last adjusted by regulation, whichever is later (i.e., the
Previous Period), to the year in which the Annual CPI-U is most recently
published (i.e., the Current Period), using the following formula:
Percent change in the Annual CPI-U = [(Annual CPI-U for Current Period -
Annual CPI-U for Previous Period) / Annual CPI-U for Previous Period] x
100. This cumulative percent change value is rounded to one decimal
place.
(b) Significance threshold. (1) A cumulative increase in the Annual
CPI-U equal to three percent or more constitutes a significant increase
in the Consumer Price Index within the meaning of 33 U.S.C. 2704(d)(4).
(2) Not later than every three years from the year the limit of
liability was last adjusted for inflation, BOEM will evaluate whether
the cumulative percent change in the Annual CPI-U since that year has
reached a significance threshold of three percent or greater.
(3) For any three-year period evaluated under paragraph (b)(2) of
this section in which the cumulative percent increase in the Annual CPI-
U is less than three percent, if BOEM has not issued an inflation
adjustment during that period, BOEM will publish a notice of no
inflation adjustment to the offshore facility limit of liability for
damages in the Federal Register.
(4) Once the three-percent threshold is reached, BOEM will increase
by final rule the offshore facility limit of liability for damages in
Sec. 553.702 by an amount equal to the cumulative percent change in the
Annual CPI-U from the year the limit was established by statute, or last
adjusted by regulation, whichever is later. After this adjustment is
made, BOEM will resume its process of conducting a review every three
years.
(5) Nothing in this section will prevent BOEM, in BOEM's sole
discretion, from adjusting the offshore facility limit of liability for
damages for inflation by regulation issued more frequently than every
three years.
(c) Formula for calculating inflation adjustments. BOEM calculates
adjustments to the offshore facility limit of liability in 30 CFR
553.702 for inflation using the following formula:

New limit of liability = Previous limit of liability + (Previous limit
of liability x the decimal equivalent of the percent change in the
Annual CPI-U calculated under paragraph (a) of this section), then
rounded to the closest $100.

Sec. 553.704 How will BOEM publish the offshore facility limit
of liability adjustment?

BOEM will publish the inflation-adjusted limit of liability, and any
statutory amendments to that limit of liability in the Federal Register,
as amendments to Sec. 553.702. Updates to the limit of liability under
this section are effective on the 90th day after publication in the
Federal Register of the amendments to Sec. 553.702, unless otherwise
specified by statute (in the event of a statutory amendment to the limit
of liability), or in the Federal Register rule amending Sec. 553.702.

Sec. Appendix to Part 553--List of U.S. Geological Survey Topographic
Maps

Alabama (1:24,000 scale): Bellefontaine; Bon Secour Bay; Bridgehead;
Coden; Daphne; Fort Morgan; Fort Morgan NW; Grand Bay; Grand Bay SW;
Gulf Shores; Heron Bay; Hollingers Island; Isle Aux Herbes; Kreole;
Lillian; Little Dauphin Island; Little Point Clear; Magnolia Springs;
Mobile; Orange Beach; Perdido Beach; Petit Bois Island; Petit Bois Pass;
Pine Beach; Point Clear; Saint Andrews Bay; West Pensacola.

[[Page 448]]

Alaska (1:63,360 scale): Afognak (A-1, A-2, A-3, A-4, A-5, A-0&B-0,
B-1, B-2, B-3, C-1&2, C-2&3, C-5, C-6, D-1, D-4, D-5); Anchorage (A-1,
A-2, A-3, A-4, A-8, B-7, B-8); Barrow (A-1, A-2, A-3, A-4, A-5, B-3, B-
4); Baird Mts. (A-6); Barter Island (A-3, A-4, A-5); Beechy Point (A-1,
A-2, B-1, B-2, B-3, B-4, B-5, C-4, C-5); Bering Glacier (A-1, A-2, A-3,
A-4, A-5, A-6, A-7, A-8); Black (A-1, A-2, B-1, C-1); Blying Sound (C-7,
C-8, D-1&2, D-3, D-4, D-5, D-6, D-7, D-8); Candle (D-6); Cordova (A-1,
A-2, A-3, A-4, A-7&8, B-2, B-3, B-4, B-5, B-6, B-7, B-8, C-5, C-6, C-7,
C-8, D-6, D-7, D-8); De Long Mts. (D-4, D-5); Demarcation Point (C-1, C-
2, D-2, D-3); Flaxman Island (A-1, A-3, A-4, A-5, B-5); Harrison Bay (B-
1, B-2, B-3, B-4, C-1, C-3, C-4, C-5, D-4, D-5); Icy Bay (D1, D-2&3);
Iliamna (A-2, A-3, A-4, B-2, B-3, C-1, C-2, D-1); Karluk (A-1, A-2, B-2,
B-3, C-1, C-2, C-4&5, C-6); Kenai (A-4, A-5, A-7, A-8, B-4, B-6, B-7, B-
8, C-4, C-5, C-6, C-7, D-1, D-2, D-3, D-4, D-5); Kodiak (A-3, A-4, A-5,
A-6, B-1&2, B-3, B-4, B-6, C-1, C-2, C-3, C-5, C-6, D-1, D-2, D-3, D-4,
D-5, D-6); Kotzebue (A-1, A-2, A-3, A-4, B-4, B-6, C-1, C-4, C-5, C-6,
D-1, D-2); Kwiguk (C-6, D-6); Meade River (D-1, D-3, D-4, D-5);
Middleton Island (B-7, D-1&2); Mt. Katmai (A-1, A-2, A-3; B-1); Mt.
Michelson (D-1, D-2, D-3); Mt. St. Elias (A-5); Noatak (A-1, A-2, A-3,
A-4, B-4, C-4, C-5, D-6, D-7); Nome (B-1, C-1, C-2, C-3, D-3, D-4, D-7);
Norton Bay (A-4, B-4, B-5, B-6, C-4, C-5, C-6, D-4, D-5, D-6); Point
Hope (A-1, A-2, B-2, B-3, C-2, C-3, D-1, D-2); Point Lay (A-3&4, B-2&3,
C-2, D-1, D-2); Selawik (A-5, A-6, B-5, B-6, C-5, C-6, D-6); Seldovia
(A-3, A-4, A-5, A-6, B-1, B-2, B-3, B-4, B-5, B-6, C-1, C-2, C-3, C-4,
C-5, D-1, D-3, D-4, D-5, D-8); Seward (A-1, A-2, A-3, A-4, A-5, A-6, A-
7, B-1, B-2, B-3, B-4, B-5, C-1, C-2, C-3, C-4, C-5, D-1, D-2, D-3, D-4,
D-5, D-6, D-7, D-8); Shishmaref (A-2, A-3, A-4, B-1, B-2, B-3); Solomon
(B-2, B-3, B-6, C-1, C-2, C-3, C-4, C-5, C-6); St. Michael (A-2, A-3, A-
4, A-5, A-6, B-1, B-2, C-1, C-2); Teller (A-2, A-3, A-4, B-3, B-4, B-5,
B-6, C-6, C-7, D-4, D-5, D-6, D-8); Teshekpuk (D-1, D-2, D-3, D-4, D-5);
Tyonek (A-1, A-2, A-3, A-4, B-1, B-2); Unalakleet (B-5, B-6, C-4, C-5,
D-4); Valdez (A-7, A-8); Wainwright (A-5, A-6&7, B-2, B-3, B-4, B-5&6,
C-2, C-3, D-1, D-2; Yakutat (A-1, A-2, A-2, B-3, B-4, B-5, C-4, C-5, C-
6, C-7, C-8, D-3, D-4, D-5, D-6, D-8).
California (1:24,000 scale): Arroyo Grande NE; Beverly Hills;
Carpinteria; Casmalia; Dana Point; Del Mar; Dos Pueblos Canyon;
Encinitas; Gaviota; Goleta; Guadalupe; Imperial Beach; Laguna Beach; La
Jolla; Las Pulgas Canyon; Lompoc Hills; Long Beach; Los Alamitos; Malibu
Beach; Morro Bay South; National City; Newport Beach; Oceano; Oceanside;
Oxnard; Pismo Beach; Pitas Point; Point Arguello; Point Conception;
Point Dune; Point Loma; Point Mugu; Point Sal; Port San Luis; Rancho
Santa Fe; Redondo Beach; Sacate; San Clemente; San Juan Capistrano; San
Luis Rey; San Onofre Bluff; San Pedro; Santa Barbara; Saticoy; Seal
Beach; Surf; Tajiguas; Topanga; Torrance; Tranquillon Mountain; Triunfo
Pass; Tustin; Venice; Ventura; White Ledge Peak.
Florida (1:24,000 scale): Allanton; Alligator Bay; Anna Maria;
Apalachicola; Aripeka; Bayport; Beacon Beach; Beacon Hill; Bee Ridge;
Belle Meade; Belle Meade NW; Beverly; Big Lostmans Bay; Bird Keys;
Bokeelia; Bonita Springs; Bradenton; Bradenton Beach; Bruce; Bunker;
Cape Romano; Cape Saint George; Cape San Blas; Captiva; Carrabelle;
Cedar Key; Chassahowitzka; Chassahowitzka Bay; Chiefland SW; Choctaw
Beach; Chokoloskee; Clearwater; Clive Key; Cobb Rocks; Cockroach Bay;
Crawfordville East; Crooked Island; Crooked Point; Cross City SW;
Crystal River; Destin; Dog Island; Dunedin; East Pass; Egmont Key; El
Jobean; Elfers; Englewood; Englewood NW; Estero; Everglades City; Fivay
Junction; Flamingo; Fort Barrancas; Fort Myers Beach; Fort Myers SW;
Fort Walton Beach; Freeport; Gandy Bridge; Garcon Point; Gator Hook
Swamp; Gibsonton; Goose Island; Grayton Beach; Green Point; Gulf Breeze;
Harney River; Harold SE; Holley; Holt SW; Homosassa; Horseshoe Beach;
Indian Pass; Jackson River; Jena; Keaton Beach; Laguna Beach; Lake
Ingraham East; Lake Ingraham West; Lake Wimico; Laurel; Lebanon Station;
Lighthouse Point; Lillian; Long Point; Lostmans River Ranger Station;
Manlin Hammock; Marco Island; Mary Esther; Matlacha; McIntyre; Milton
South; Miramar Beach; Myakka River; Naples North; Naples South; Navarre;
New Inlet; Niceville; Nutall Rise; Ochopee; Okefenokee Slough; Oldsmar;
Orange Beach; Oriole Beach; Overstreet; Ozello; Pace; Palmetto; Panama
City; Panama City Beach; Panther Key; Pass-A-Grille Beach; Pavillion
Key; Pensacola; Perdido Bay; Pickett Bay; Pine Island Center; Placida;
Plover Key; Point Washington; Port Boca Grande; Port Richey; Port Richey
NE; Port Saint Joe; Port Tampa; Punta Gorda; Punta Gorda SE; Punta Gorda
SW; Red Head; Red Level; Rock Islands; Royal Palm Hammock; Safety
Harbor; Saint Joseph Point; Saint Joseph Spit; Saint Marks; Saint Marks
NE; Saint Petersburg; Saint Teresa Beach; Salem SW; Sandy Key; Sanibel;
Sarasota; Seahorse Key; Seminole; Seminole Hills; Shark Point; Shark
River Island; Shired Island; Snipe Island; Sopchoppy; South of Holley;
Southport; Sprague Island; Spring Creek; Springfield; Steinhatchee;
Steinhatchee SE; Steinhatchee SW; Sugar Hill; Sumner; Suwannee; Tampa;
Tarpon Springs; Valparaiso; Venice; Vista; Waccassasa Bay; Ward Basin;
Warrior Swamp; Weavers Station; Weeki Wachee Spring; West Bay; West
Pass; West Pensacola; Whitewater Bay West; Withlacoochee Bay; Wulfert;
Yankeetown.
Louisiana (1:24,000 scale): Alligator Point; Barataria Pass; Bastian
Bay; Bay Batiste;

[[Page 449]]

Bay Coquette; Bay Courant; Bay Dosgris; Bay Ronquille; Bay Tambour;
Bayou Blanc; Bayou Lucien; Belle Isle; Belle Pass; Big Constance Lake;
Black Bay North; Black Bay South; Breton Islands; Breton Islands SE;
Buras; Burrwood Bayou East; Burwood Bayou West; Calumet Island; Cameron;
Caminada Pass; Cat Island; Cat Island Pass; Central Isles Dernieres;
Chandeleur Light; Chef Mentur; Cheniere Au Tigre; Cocodrie; Coquille
Point; Cow Island; Creole; Cypremort Point; Deep Lake; Dixon Bay; Dog
Lake; Door Point; East Bay Junop; Eastern Isles; Dernieres; Ellerslie;
Empire; English Lookout; False Mouth Bayou; Fearman Lake; Floating Turf
Bayou; Fourleague Bay; Franklin; Freemason Island; Garden Island Pass;
Grand Bayou; Grand Bayou du Large; Grand Chenier; Grand Gosier Islands;
Grand Isle; Hackberry Beach; Hammock Lake; Happy Jack; Hebert Lake; Hell
Hole Bayou; Hog Bayou; Holly Beach; Intercoastal City; Isle Au Pitre;
Jacko Bay; Johnson Bayou; Kemper; Lake Athanasio; Lake Cuatro Caballo;
Lake Eloi; Lake Eugene; Lake Felicity; Lake La Graisse; Lake Merchant;
Lake Point; Lake Salve; Lake Tambour; Leeville; Lena Lagoon; Lost Lake;
Main Pass; Malheureux Point; Marone Point; Martello Castle; Mink Bayou;
Mitchell Key; Morgan City SW; Morgan Harbor; Mound Point; Mulberry
Island East; Mulberry Island West; New Harbor Islands; North Islands;
Oak Mound Bayou; Oyster Bayou; Pass A Loutre East; Pass A Loutre West;
Pass du Bois; Pass Tante Phine; Pecan Island; Pelican Pass; Peveto
Beach; Pilottown; Plumb Bayou; Point Au Fer; Point Au Fer NE; Point
Chevreuil; Point Chicot; Port Arthur South; Port Sulphur; Pte. Aux
Marchuttes; Proctor Point; Pumpkin Islands; Redfish Point; Rollover
Lake; Sabine Pass; Saint Joe Pass; Smith Bayou; South of South Pass;
South Pass; Stake Islands; Taylor Pass; Texas Point; Three Mile Bay;
Tigre Lagoon; Timbalier Island; Triumph; Venice; Weeks; West of Johnson
Bayou; Western Isles Dernieres; Wilkinson Bay; Yscloskey.
Mississippi (1:24,000 scale): Bay Saint Louis; Biloxi; Cat Island;
Chandeleur Light; Deer Island; Dog Keys Pass; English Lookout; Gautier
North; Gautier South; Grand Bay SW; Gulfport North; Gulfport NW;
Gulfport South; Horn Island East; Horn Island West; Isle Au Pitre;
Kreole; Ocean Springs; Pascagoula North; Pascagoula South; Pass
Christian; Petit Bois Island; Saint Joe Pass; Ship Island; Waveland.
Texas (1:24,000 scale): Allyns Bright; Anahuac; Aransas Pass;
Austwell; Bacliff; Bayside; Big Hill Bayou; Brown Cedar Cut; Caplen;
Carancahua Pass; Cedar Lakes East; Cedar Lakes West; Cedar Lane NE;
Christmas Point; Clam Lake; Corpus Christi; Cove; Crane Islands NW;
Crane Islands SW; Decros Point; Dressing Point; Estes; Flake; Freeport;
Frozen Point; Galveston; Green Island; Hawk Island; High Island;
Hitchcock; Hoskins Mound; Jones Creek; Keller Bay; Kleberg Point; La
Comal; La Leona; La Parra Ranch NE; Laguna Vista; Lake Austin; Lake
Como; Lake Stephenson; Lamar; Long Island; Los Amigos; Windmill; Maria
Estella Well; Matagorda; Matagorda SW; Mesquite Bay; Mission Bay;
Morgans Point; Mosquito Point; Mouth of Rio Grande; Mud Lake; North of
Port Isabel NW; North of Port Isabel SW; Oak Island; Olivia; Oso Creek
NE; Oyster Creek; Palacios; Palacios NE; Palacios Point; Palacios SE;
Panther Point; Panther Point NE; Pass Cavallo SW; Pita Island; Point
Comfort; Point of Rocks; Port Aransas; Port Arthur South; Port Bolivar;
Port Ingleside; Port Isabel; Port Isabel NW; Port Lavaca East; Port
Mansfield; Port O'Connor; Portland; Potrero Cortado; Potrero Lopeno NW;
Potrero Lopeno SE; Potrero Lopeno SW; Rockport; Sabine Pass; San Luis
Pass; Sargent; Sea Isle; Seadrift; Seadrift NE; Smith Point; South Bird
Island; South Bird Island NW; South Bird Island SE; South of Palacios
Point; South of Potrero Lopeno NE; South of Potrero Lopeno NW; South of
Potrero Lopeno SE; South of Star Lake; St. Charles Bay; St. Charles Bay
SE; St. Charles Bay SW; Star Lake; Texas City; Texas Point; The Jetties;
Three Islands; Tivoli SE; Turtle Bay; Umbrella Point; Virginia Point;
West of Johnson Bayou; Whites Ranch; Yarborough Pass.

PART 556_LEASING OF SULFUR OR OIL AND GAS AND BONDING REQUIREMENTS
IN THE OUTER CONTINENTAL SHELF--Table of Contents

Subpart A_General Provisions

Sec.
556.100 Statement of policy.
556.101 Purpose.
556.102 Authority.
556.103 Cross references.
556.104 Information collection and proprietary information.
556.105 Acronyms and definitions.
556.106 Service fees.
556.107 Corporate seal requirements.

Subpart B_Oil and Gas Five Year Leasing Program

556.200 What is the Five Year leasing program?
556.201 Does BOEM consider multiple uses of the OCS?
556.202 How does BOEM start the Five Year program preparation process?
556.203 What does BOEM do before publishing a proposed Five Year
program?

[[Page 450]]

556.204 How do Governments and citizens comment on a proposed Five Year
program?
556.205 What does BOEM do before approving a proposed final Five Year
program or a significant revision of a previously-approved
Five Year program?

Subpart C_Planning and Holding a Lease Sale

556.300 What reports may BOEM and other Federal agencies prepare before
a lease sale?
556.301 What is a Call for Information and Nominations?
556.302 What does BOEM do with the information from the Call?
556.303 What does BOEM do if an area proposed for leasing is within
three nautical miles of the seaward boundary of a coastal
State?
556.304 How is a proposed notice of sale prepared?
556.305 How does BOEM coordinate and consult with States regarding a
proposed notice of sale?
556.306 What if a potentially oil or gas bearing area underlies both the
OCS and lands subject to State jurisdiction?
556.307 What does BOEM do with comments and recommendations received on
the proposed notice of sale?
556.308 How does BOEM conduct a lease sale?
556.309 Does BOEM offer blocks in a sale that is not on the Five Year
program schedule (called a Supplemental Sale)?

Subpart D_Qualifications

556.400 When must I demonstrate that I am qualified to hold a lease on
the OCS?
556.401 What do I need to show to become qualified to hold a lease on
the OCS and obtain a qualification number?
556.402 How do I make the necessary showing to qualify and obtain a
qualification number?
556.403 Under what circumstances may I be disqualified from holding a
lease on the OCS?
556.404 What do the non-procurement debarment rules require that I do?
556.405 When must I notify BOEM of mergers, name changes, or changes of
business form?

Subpart E_Issuance of a Lease

How To Bid

556.500 Once qualified, how do I submit a bid?
556.501 What information do I need to submit with my bid?

Restrictions on Joint Bidding

556.511 Are there restrictions on bidding with others and do those
restrictions affect my ability to bid?
556.512 What bids may be disqualified?
556.513 When must I file a statement of production?
556.514 How do I determine my production for purposes of the restricted
joint bidders list?
556.515 May a person be exempted from joint bidding restrictions?

How does BOEM act on bids?

556.516 What does BOEM do with my bid?
556.517 What may I do if my bid is rejected?

Awarding the Lease

556.520 What happens if I am the successful high bidder and BOEM accepts
my bid?
556.521 When is my lease effective?
556.522 What are the terms and conditions of the lease and when are they
published?

Subpart F_Lease Terms and Obligations

Length of Lease

556.600 What is the primary term of my oil and gas lease?
556.601 How may I maintain my oil and gas lease beyond the primary term?
556.602 What is the primary term of my sulfur lease?
556.603 How may I maintain my sulfur lease beyond the primary term?

Lease Obligations

56.604 What are my rights and obligations as a record title owner?
556.605 What are my rights and obligations as an operating rights owner?

Helium

556.606 What must a lessee do if BOEM elects to extract helium from a
lease?

Subpart G_Transferring All or Part of the Record Title Interest in a
Lease

556.700 May I assign or sublease all or any part of the record title
interest in my lease?
556.701 How do I seek approval of an assignment of the record title
interest in my lease, or a severance of operating rights from
that record title interest?
556.702 When will my assignment result in a segregated lease?
556.703 What is the effect of the approval of the assignment of 100
percent of the record title in a particular aliquot(s) of my
lease and the resulting lease segregation?

[[Page 451]]

556.704 When would BOEM disapprove an assignment or sublease of an
interest in my lease?
556.705 How do I transfer the interest of a deceased natural person who
was a lessee?
556.706 What if I want to transfer record title interests in more than
one lease at the same time, but to different parties?
556.707 What if I want to transfer different types of lease interests
(not only record title interests) in the same lease to
different parties?
556.708 What if I want to transfer my record title interests in more
than one lease to the same party?
556.709 What if I want to transfer my record title interest in one lease
to multiple parties?
556.710 What is the effect of an assignment of a lease on an assignor's
liability under the lease?
556.711 What is the effect of a record title holder's sublease of
operating rights on the record title holder's liability?
556.712 What is the effective date of a transfer?
556.713 What is the effect of an assignment of a lease on an assignee's
liability under the lease?
556.714 As a restricted joint bidder, may I transfer an interest to
another restricted joint bidder?
556.715 Are there any interests I may transfer or record without BOEM
approval?
556.716 What must I do with respect to the designation of operator on a
lease when a transfer of record title is submitted?

Subpart H_Transferring Operating Rights in All or Part of a Lease

556.800 As an operating rights owner, may I assign all or part of my
operating rights interest?
556.801 How do I seek approval of an assignment of my operating rights?
556.802 When would BOEM disapprove the assignment of all or part of my
operating rights interest?
556.803 What if I want to assign operating rights interests in more than
one lease at the same time, but to different parties?
556.804 What if I want to assign my operating rights interest in a lease
to multiple parties?
556.805 What is the effect of an operating rights owner's assignment of
operating rights on the assignor's liability?
556.806 What is the effective date of an assignment of operating rights?
556.807 What is the effect of an assignment of operating rights on an
assignee's liability?
556.808 As an operating rights owner, are there any interests I may
assign without BOEM approval?
556.809 [Reserved]
556.810 What must I do with respect to the designation of operator on a
lease when a transfer of operating rights ownership is
submitted?

Subpart I_Bonding or Other Financial Assurance

556.900 Bond requirements for an oil and gas or sulfur lease.
556.901 Additional bonds.
556.902 General requirements for bonds.
556.903 Lapse of bond.
556.904 Lease-specific abandonment accounts.
556.905 Using a third-party guarantee instead of a bond.
556.906 Termination of the period of liability and cancellation of a
bond.
556.907 Forfeiture of bonds and/or other securities.

Subpart J_Bonus or Royalty Credits for Exchange of Certain Leases

556.1000 Leases formerly eligible for a bonus or royalty credit.

Subpart K_Ending a Lease

556.1100 How does a lease expire?
556.1101 May I relinquish my lease or an aliquot part thereof?
556.1102 Under what circumstances will BOEM cancel my lease?

Subpart L_Leases Maintained Under Section 6 of OCSLA

556.1200 Effect of regulations on lease.
556.1201 Section 6(a) leases and leases other than those for oil, gas,
or sulfur.

Subpart M_Environmental Studies

556.1300 Environmental studies.

Authority: 30 U.S.C. 1701 note, 30 U.S.C. 1711, 31 U.S.C. 9701, 42
U.S.C. 6213, 43 U.S.C. 1331 note, 43 U.S.C. 1334, 43 U.SC. 1801-1802.

Source: 81 FR 18152, Mar. 30, 2016, unless otherwise noted.

Subpart A_General Provisions

Sec. 556.100 Statement of policy.

The management of Outer Continental Shelf (OCS) resources is to be
conducted in accordance with the findings, purposes, and policy
directions provided by the Outer Continental Shelf Lands Act Amendments
of 1978 (OCSLA or the Act) (43 U.S.C. 1332,

[[Page 452]]

1801, 1802), and other executive, legislative, judicial and departmental
guidance. The Secretary of the Interior (the Secretary) will consider
available environmental information in making decisions affecting OCS
resources.

Sec. 556.101 Purpose.

The purpose of the regulations in this part is to establish the
procedures under which the Secretary will exercise the authority to
administer a leasing program for oil and gas, and sulfur. The
regulations pertaining to the procedures under which the Secretary will
exercise the authority to administer a program to grant rights-of-use
and easements are found in part 550 of this chapter.

Sec. 556.102 Authority.

(a) The Outer Continental Shelf Lands Act (OCSLA) (43 U.S.C. 1334)
authorizes the Secretary of the Interior to issue, on a competitive
basis, leases for oil and gas, and sulfur, in submerged lands of the
OCS. The Act authorizes the Secretary to grant rights-of-way and
easements through the submerged lands of the OCS.
(b) The Federal Oil and Gas Royalty Management Act of 1982 (FOGRMA)
(30 U.S.C. 1711) governs oil and gas royalty management and requires the
development of enforcement practices to ensure the prompt and proper
collection of oil and gas revenues owed to the U.S.
(c) The Independent Offices Appropriations Act of 1952 (IOAA) (31
U.S.C. 9701) authorizes fees and charges for Federal government
services.
(d) The Energy Policy and Conservation Act of 1975 (42 U.S.C. 6213)
prohibits joint bidding by major oil and gas producers.
(e) The Gulf of Mexico Energy Security Act of 2006 (GOMESA) (Pub. L.
109-432, 43 U.S.C. 1331 note):
(1) Shares leasing revenues with Gulf producing states and the Land
& Water Conservation Fund for coastal restoration projects; and
(2) Allows companies to exchange certain existing leases in
moratorium areas for bonus and royalty credits to be used on other Gulf
of Mexico leases.

Sec. 556.103 Cross references.

The following includes some of the major regulations relevant to
offshore oil and gas development:
(a) For other applicable Bureau of Ocean Energy Management (BOEM)
oil and gas regulations, see 30 CFR parts 550 through 560.
(b) For Bureau of Safety and Environmental Enforcement (BSEE)
regulations governing exploration, development and production, and oil
spill response, see 30 CFR chapter II.
(c) For Office of Natural Resources Revenue (ONRR) regulations
related to rentals, royalties, and fees, see 30 CFR chapter XII.
(d) For BOEM regulations governing the appeal of an order or
decision issued under the regulations in this part, see 30 CFR part 590.
(e) For regulations on the National Environmental Policy Act (NEPA),
see 40 CFR 1500-1508 and 43 CFR part 46.
(f) For ocean dumping sites, see the U.S. Environmental Protection
Agency (USEPA) listing--40 CFR part 228.
(g) For air quality, see USEPA regulations at 40 CFR part 55 and
BOEM regulations at 30 CFR part 550 subparts B and C.
(h) For related National Oceanic and Atmospheric Administration
(NOAA) programs, see:
(1) Marine Sanctuary regulations, 15 CFR part 922;
(2) Fishermen's Contingency Fund, 50 CFR part 296;
(3) Coastal Zone Management Act (CZMA), 15 CFR part 930;
(4) Essential Fish Habitat, 50 CFR 600.90.
(i) For U.S. Coast Guard (USCG) regulations on the oil spill
liability of vessels and operators, see 33 CFR parts 132, 135, and 136.
(j) For USCG regulations on port access routes, see 33 CFR part 164.
(k) For Department of Transportation regulations on offshore
pipeline facilities, see 49 CFR part 195.
(1) For Department of Defense regulations on military activities on
offshore areas, see 32 CFR part 252.

Sec. 556.104 Information collection and proprietary information.

(a) Information collection. (1) The Office of Management and Budget
(OMB)

[[Page 453]]

approved the collection of information under 44 U.S.C. 3501-3521), and
assigned OMB Control Number 1010-0006. The title of this collection of
information is ``Leasing of Sulfur or Oil and Gas in the Outer
Continental Shelf (30 CFR part 550, part 556, and part 560).''
(2) BOEM collects this information to determine if an applicant
seeking to obtain a lease or right-of-use and easement (RUE) on the OCS
is qualified to hold such a lease or RUE and to determine whether any
such applicant can meet the monetary and non-monetary requirements
associated with a lease or RUE. Responses to this information collection
are either required to obtain or retain a benefit or are mandatory under
OCSLA (43 U.S.C. 1331-1356a). BOEM will protect proprietary information
collected according to section 26 of OCSLA (43 U.S.C. 1352), and this
section.
(3) The Paperwork Reduction Act of 1995 (44 U.S.C. 3501-3521)
requires us to inform the public that an agency may not conduct or
sponsor, and that no one is required to respond to, a collection of
information unless it displays a current and valid OMB control number.
(4) Send comments regarding any aspect of the collection of
information under this part, including suggestions for reducing the
burden, to the Information Collection Clearance Officer, Bureau of Ocean
Energy Management, by mail at 45600 Woodland Road, Sterling, VA 20166 or
by email to [email protected], or by phone at (703) 787-1025.
(b) Proprietary information. (1) Any proprietary information
maintained by BOEM will be subject to the requirements of 43 CFR part 2.
(2) No proprietary information received by BOEM under 43 U.S.C.
1352(c) will be transmitted to any affected State unless the lessee, to
whom such information applies, or the permittee and all persons, to whom
such permittee has sold such information under promise of
confidentiality, agree to such transmittal.
(c) Proprietary information in response to a Call for Information
and Nominations (Call).
(1) A specific indication of interest in an area received in
response to a Call issued by the Secretary is proprietary information.
(2) Notwithstanding paragraph (c)(1) of this section, BOEM may
provide a summary of indications of interest in areas received in
response to a Call for a proposed sale.

Sec. 556.105 Acronyms and definitions.

(a) Acronyms and terms used in this part have the following
meanings:

ASTM American Society for Testing and Materials
BAST Best Available and Safest Technology
BOEM Bureau of Ocean Energy Management
BSEE Bureau of Safety and Environmental Enforcement
CFR Code of Federal Regulations
CPA Central Planning Area of the GOM
CZMA Coastal Zone Management Act
DOI Department of the Interior
DOCD Development Operations Coordination Document
DOO Designation of Operator
DPP Development and Production Plan
EIA Environmental Impact Analysis
EP Exploration Plan
EPA Eastern Planning Area of the GOM
EPAct Energy Policy Act of 2005
FNOS Final Notice of Sale
FOGRMA Federal Oil and Gas Royalty Management Act of 1982
G&G Geological and Geophysical
GDIS Geophysical Data and Information Statement
GOM Gulf of Mexico
GOMESA Gulf of Mexico Energy Security Act of 2006
IOAA Independent Offices Appropriations Act of 1952
LLC Limited Liability Company
MBB Mapping and Boundary Branch
NAD North American Datum
NEPA National Environmental Policy Act of 1969
NGPA Natural Gas Processors Association
NOAA National Oceanic and Atmospheric Administration
NTL Notice to Lessees
OCS Outer Continental Shelf
OCSLA Outer Continental Shelf Lands Act
OMB Office of Management and Budget
ONRR Office of Natural Resources Revenue
OPD Official Protraction Diagram
PNOS Proposed Notice of Sale
PRA Paperwork Reduction Act
ROW Right of way
RSV Royalty Suspension Volume
RUE Right of Use and Easement
SLA Submerged Lands Act of 1953
U.S. United States
U.S.C. United States Code
USCG U.S. Coast Guard

[[Page 454]]

USEPA U.S. Environmental Protection Agency
UTM Universal Transverse Mercator coordinate system
WPA Western Planning Area of the GOM

(b) As used in this part, each of the terms and phrases listed below
has the meaning given in the Act or as defined in this section.
Act means the Outer Continental Shelf Lands Act, as amended (OCSLA)
(43 U.S.C. 1331-1356a).
Affected State means, with respect to any program, plan, lease sale,
or other activity proposed, conducted, or approved pursuant to the
provisions of OCSLA, any State:
(i) The laws of which are declared, pursuant to section 4(a)(2) of
OCSLA (43 U.S.C. 1333(a)(2)), to be the law of the United States for the
portion of the OCS on which such activity is, or is proposed to be,
conducted;
(ii) Which is, or is proposed to be, directly connected by
transportation facilities to any artificial island or structure referred
to in section 4(a)(1) of OCSLA (43 U.S.C. 1333(a)(1));
(iii) Which is receiving, or in accordance with the proposed
activity will receive, oil for processing, refining, or transshipment
that was extracted from the OCS and transported directly to that State
by means of one or more vessels or by a combination of means, including
a vessel;
(iv) Which is designated by the Secretary as a State in which there
is a substantial probability of significant impact on or damage to the
coastal, marine, or human environment; or a State in which there will be
significant changes in the social, governmental, or economic
infrastructure resulting from the exploration, development, and
production of oil and gas anywhere on the OCS; or
(v) In which the Secretary finds that because of such activity,
there is, or will be, a significant risk of serious damage, due to
factors such as prevailing winds and currents, to the marine or coastal
environment in the event of any oil spill, blowout, or release of oil or
gas from one or more vessels, pipelines, or other transshipment
facilities.
Aliquot or Aliquot part means an officially designated subdivision
of a lease's area, which can be a half of a lease (\1/2\), a quarter of
a lease (\1/4\), a quarter of a quarter of a lease (\1/4\ \1/4\), or a
quarter of a quarter of a quarter of a lease (\1/4\ \1/4\ \1/4\).
Authorized officer means any person authorized by law or by
delegation of authority to or within BOEM to perform the duties
described in this part.
Average daily production means the total of all production in an
applicable production period that is chargeable under Sec. 556.514
divided by the exact number of calendar days in the applicable
production period.
Barrel means 42 U.S. gallons. All measurements of crude oil and
natural gas liquids under this section must be at 60 [deg]F.
(i) For purposes of computing production and reporting of natural
gas, 5,626 cubic feet of natural gas at 14.73 pounds per square inch
equals one barrel.
(ii) For purposes of computing production and reporting of natural
gas liquids, 1.454 barrels of natural gas liquids at 60 [deg]F equals
one barrel of crude oil.
Bidding unit means one or more OCS blocks, or any portion thereof,
that may be bid upon as a single administrative unit and will become a
single lease. The term `tract,'' as defined in this section, may be used
interchangeably with the term ``bidding unit.''
BOEM means Bureau of Ocean Energy Management of the U.S. Department
of the Interior.
Bonus or royalty credit means a legal instrument or other written
documentation approved by BOEM, or an entry in an account managed by the
Secretary, that a bidder or lessee may use in lieu of any other monetary
payment for a bonus or a royalty due on oil or gas production from
certain leases, as specified in, and permitted by, the Gulf of Mexico
Energy Security Act of 2006, Pub. L. 109-432 (Div. C, Title 1), 120
Stat. 3000 (2006), codified at 43 U.S.C. 1331, note.
BSEE means Bureau of Safety and Environmental Enforcement of the
U.S. Department of the Interior.
Central Planning Area (CPA) means that portion of the Gulf of Mexico
that lies southerly of Louisiana, Mississippi, and Alabama. Precise
boundary information is available from the BOEM

[[Page 455]]

Leasing Division, Mapping and Boundary Branch (MBB).
Coastal environment means the physical, atmospheric, and biological
components, conditions, and factors that interactively determine the
productivity, state, condition, and quality of the terrestrial ecosystem
from the shoreline inland to the boundaries of the coastal zone.
Coastal zone means the coastal waters (including the lands therein
and thereunder) and the adjacent shorelands (including the water therein
and thereunder), strongly influenced by each other and in proximity to
the shorelines of one or more of the several coastal States, and
includes islands, transition and intertidal areas, salt marshes,
wetlands, and beaches, whose zone extends seaward to the outer limit of
the United States territorial sea and extends inland from the shore
lines to the extent necessary to control shorelands, the uses of which
have a direct and significant impact on the coastal waters, and the
inland boundaries of which may be identified by the several coastal
States, under section 305(b)(1) of the Coastal Zone Management Act
(CZMA) of 1972, 16 U.S.C. 1454(b)(1).
Coastline means the line of mean ordinary low water along that
portion of the coast in direct contact with the open sea and the line
marking the seaward limit of inland waters.
Crude oil means a mixture of liquid hydrocarbons, including
condensate that exists in natural underground reservoirs and remains
liquid at atmospheric pressure after passing through surface separating
facilities, but does not include liquid hydrocarbons produced from tar
sand, gilsonite, oil shale, or coal.
Designated operator means a person authorized to act on your behalf
and fulfill your obligations under the Act, the lease, and the
regulations, who has been designated as an operator by all record title
holders and all operating rights owners that own an operating rights
interest in the aliquot/depths in which the designated operator, to
which the Designation of Operator form applies, will be operating, and
who has been approved by BOEM to act as designated operator.
Desoto Canyon OPD means the Official Protraction Diagram (OPD)
designated as Desoto Canyon that has a western edge located at the
universal transverse mercator (UTM) X coordinate 1,346,400 in the North
American Datum of 1927 (NAD27).
Destin Dome OPD means the Official Protraction Diagram (OPD)
designated as Destin Dome that has a western edge located at the
Universal Transverse Mercator (UTM) X coordinate 1,393,920 in the NAD27.
Development block means a block, including a block susceptible to
drainage, which is located on the same general geologic structure as an
existing lease having a well with indicated hydrocarbons; a reservoir
may or may not be interpreted to extend on to the block.
Director means the Director of the BOEM of the U.S. Department of
the Interior, or an official authorized to act on the Director's behalf.
Eastern Planning Area (EPA) means that portion of the Gulf of Mexico
that lies southerly and westerly of Florida. Precise boundary
information is available from the BOEM Leasing Division, Mapping and
Boundary Branch.
Economic interest means any right to, or any right dependent upon,
production of crude oil, natural gas, or natural gas liquids and
includes, but is not limited to: a royalty interest; an overriding
royalty interest, whether payable in cash or kind; a working interest
that does not include a record title interest or an operating rights
interest; a carried working interest; a net profits interest; or a
production payment.
Human environment means the physical, social, and economic
components, conditions, and factors that interactively determine the
state, condition, and quality of living conditions, employment, and
health of those affected, directly or indirectly, by activities
occurring on the OCS.
Initial period or primary term means the initial period referred to
in 43 U.S.C. 1337(b)(2).
Joint bid means a bid submitted by two or more persons for an oil
and gas lease under section 8(a) of the Act.
Lease means an agreement that is issued under section 8 or
maintained

[[Page 456]]

under section 6 of the Act and that authorizes exploration for, and
development and production of, minerals on the OCS. The term also means
the area covered by that agreement, whichever the context requires.
Lease interest means one or more of the following ownership
interests in an OCS oil and gas or sulfur lease: a record title
interest, an operating rights interest, or an economic interest.
Lessee means a person who has entered into a lease with the United
States to explore for, develop, and produce the leased minerals and is
therefore a record title owner of the lease, or the BOEM-approved
assignee-owner of a record title interest. The term lessee also includes
the BOEM-approved sublessee- or assignee-owner of an operating rights
interest in a lease.
Marine environment means the physical, atmospheric, and biological
components, conditions, and factors that interactively determine the
productivity, state, conditions, and quality of the marine ecosystem,
including the waters of the high seas, the contiguous zone, transitional
and intertidal areas, salt marshes, and wetlands within the coastal zone
and on the OCS.
Mineral means oil, gas, and sulfur; it also includes sand, gravel,
and salt used to facilitate the development and production of oil, gas,
and sulfur.
Natural gas means a mixture of hydrocarbons and varying quantities
of non-hydrocarbons that exist in the gaseous phase.
Natural gas liquids means liquefied petroleum products produced from
reservoir gas and liquefied at surface separators, field facilities, or
gas processing plants worldwide, including any of the following:
(i) Condensate--natural gas liquids recovered from gas well gas
(associated and non-associated) in separators or field facilities; or
(ii) Gas plant products--natural gas liquids recovered from natural
gas in gas processing plants and from field facilities. Gas plant
products include the following, as classified according to the standards
of the Natural Gas Processors Association (NGPA) or the American Society
for Testing and Materials (ASTM):
(A) Ethane--C2H6
(B) Propane--C3H8
(C) Butane--C4H10, including all products
covered by NGPA specifications for commercial butane, including
isobutane, normal butane, and other butanes--all butanes not included as
isobutane or normal butane;
(D) Butane-Propane Mixtures--All products covered by NGPA
specifications for butane-propane mixtures;
(E) Natural Gasoline--A mixture of hydrocarbons extracted from
natural gas, that meets vapor pressure, end point, and other
specifications for natural gasoline set by NGPA;
(F) Plant Condensate--A natural gas plant product recovered and
separated as a liquid at gas inlet separators or scrubbers in processing
plants or field facilities; and
(G) Other Natural Gas plant products meeting refined product
standards (i.e., gasoline, kerosene, distillate, etc.).
Operating rights means an interest created by sublease out of the
record title interest in an oil and gas lease, authorizing the owner to
explore for, develop, and/or produce the oil and gas contained within a
specified area and depth of the lease (i.e., operating rights tract).
Operating rights owner means the holder of operating rights.
Operating rights tract means the area within the lease from which
the operating rights have been severed on an aliquot basis from the
record title interest, defined by a beginning and ending depth.
Operator means the person designated as having control or management
of operations on the leased area or a portion thereof. An operator may
be a lessee, the operating rights owner, or a designated agent of the
lessee or the operating rights owner.
Outer Continental Shelf (OCS) means all submerged lands lying
seaward and outside of the area of lands beneath navigable waters as
defined in the Submerged Lands Act (43 U.S.C. 1301-1315) and of which
the subsoil and seabed appertain to the United States and are subject to
its jurisdiction and control.
Outer Continental Shelf Lands Act (OCSLA) means the Outer
Continental Shelf Lands Act (43 U.S.C. 1331-1356a), as amended.

[[Page 457]]

Owned, as used in the context of restricted joint bidding or a
statement of production, means:
(i) With respect to crude oil--having either an economic interest in
or a power of disposition over the production of crude oil;
(ii) With respect to natural gas--having either an economic interest
in or a power of disposition over the production of natural gas; and
(iii) With respect to natural gas liquids--having either an economic
interest in or a power of disposition over any natural gas liquids at
the time of completion of the liquefaction process.
Pensacola OPD means the Official Protraction Diagram (OPD)
designated as Pensacola that has a western edge located at the UTM X
coordinate 1,393,920 in the NAD27.
Person means a natural person, where so designated, or an entity,
such as a partnership, association, State, political subdivision of a
State or territory, or a private, public, or municipal corporation.
Planning area means a large portion of the OCS, consisting of
contiguous OCS blocks, defined for administrative planning purposes.
Primary term or initial period means the initial period referred to
in 43 U.S.C. 1337(b)(2).
Regional Director means the BOEM officer with responsibility and
authority for a Region within BOEM.
Regional Supervisor means the BOEM officer with responsibility and
authority for leasing or other designated program functions within a
BOEM Region.
Right-of-Use and Easement (RUE) means a right to use a portion of
the seabed at an OCS site other than on a lease you own, for the
construction and/or use of artificial islands, facilities,
installations, and other devices, established to support the
exploration, development or production of oil and gas, mineral, or
energy resources from an OCS or State submerged lands lease.
Right-of-Way (ROW) means an authorization issued by BSEE under the
authority of section 5(e) of the OCSLA (43 U.S.C. 1334(e)) for the use
of submerged lands of the Outer Continental Shelf for pipeline purposes.
Secretary means the Secretary of the Interior or an official or a
designated employee authorized to act on the Secretary's behalf.
Security or securities means any note, stock, treasury stock, bond,
debenture, evidence of indebtedness, certificate of interest or
participation in any profit-sharing agreement; collateral-trust
certificate; pre-organization certificate or subscription; transferable
share; investment contract; voting-trust certificate; certificate of
deposit for a security; fractional undivided interest in oil, gas, or
other mineral rights; or, in general, any interest or instrument
commonly known as a ``security'' or any certificate of interest or
participation in, temporary or interim certificate for, receipt for,
guarantee of, or warrant or right to subscribe to or purchase any of the
foregoing.
Single bid means a bid submitted by one person for an oil and gas
lease under section 8(a) of the Act.
Six-month bidding period means the 6-month period of time:
(i) From May 1 through October 31; or
(ii) from November 1 through April 30.
Statement of production means, in the context of joint restricted
bidders, the following production during the applicable prior production
period:
(i) The average daily production in barrels of crude oil, natural
gas, and natural gas liquids which it owned worldwide;
(ii) The average daily production in barrels of crude oil, natural
gas, and natural gas liquids owned worldwide by every subsidiary of the
reporting person;
(iii) The average daily production in barrels of crude oil, natural
gas, and natural gas liquids owned worldwide by any person or persons of
which the reporting person is a subsidiary; and
(iv) The average daily production in barrels of crude oil, natural
gas, and natural gas liquids owned worldwide by any subsidiary, other
than the reporting person, of any person or persons of which the
reporting person is a subsidiary.
Tract means one or more OCS blocks, or any leasable portion thereof,
that will be part of a single oil and gas lease. The term tract may be
used

[[Page 458]]

interchangeably with the term ``bidding unit.''
We, us, and our mean BOEM or the Department of the Interior,
depending on the context in which the word is used.
Western Planning Area (WPA) means that portion of the Gulf of Mexico
that lies south and east of Texas. Precise boundary information is
available from the Leasing Division, Mapping and Boundary Branch.
You, depending on the context of the regulations, means a bidder, a
prospective bidder, a lessee (record title owner), an operating rights
owner, an applicant seeking to become an assignee of record title or
operating rights, a designated operator or agent of the lessee, a
predecessor lessee, a RUE holder for a State or Federal lease, or a
pipeline ROW holder.

[81 FR 18152, Mar. 30, 2016, as amended at 81 FR 70358, Oct. 12, 2016]

Sec. 556.106 Service fees.

(a) The table in this paragraph shows the fees you must pay to BOEM
for the services listed. BOEM will adjust the fees periodically
according to the Implicit Price Deflator for Gross Domestic Product and
publish a document showing the adjustment in the Federal Register. If a
significant adjustment is needed to arrive at a new fee for any reason
other than inflation, then a proposed rule containing the new fees will
be published in the Federal Register for comment.

Service Fee Table
------------------------------------------------------------------------
Service--processing of the
following: Fee amount 30 CFR Citation
------------------------------------------------------------------------
(1) Assignment of record title $198 Sec. 556.701(a)
interest in Federal oil and gas
lease(s) for BOEM approval.......
(2) Sublease or Assignment of 198 Sec. 556.801(a)
operating rights interest in
Federal oil and gas lease(s) for
BOEM approval....................
(3) Required document filing for 29 Sec. 556.715(a)
record purpose, but not for BOEM Sec. 556.808(a)
approval.........................
(4) Non-required document filing 29 Sec. 556.715(b)
for record purposes.............. Sec. 556.808(b)
------------------------------------------------------------------------

(b) Evidence of payment via pay.gov of the fees listed in paragraph
(a) of this section must accompany the submission of a document for
approval or filing, or be sent to an office identified by the Regional
Director.
(c) Once a fee is paid, it is nonrefundable, even if your service
request is withdrawn.
(d) If your request is returned to you as incomplete, you are not
required to submit a new fee with the amended submission.
(e) The pay.gov Web site is accessible at https://www.pay.gov/
paygov/ or through the BOEM Web site at http://www.boem.gov/Fees-for-
Services.
(f) The fees listed in the table above apply equally to any document
or information submitted electronically pursuant to part 560, subpart E,
of this chapter.

Sec. 556.107 Corporate seal requirements.

(a) If you electronically submit to BOEM any document or information
referenced in Sec. 560.500 of this chapter, any requirement to use a
corporate seal under this chapter will be satisfied, and you will not
need to affix your corporate seal to such document or information, if:
(1) You properly file with BOEM a paper, with a corporate seal and
the signature of the authorized person(s), stating that electronic
submissions made by you will be legally binding, as set forth in Sec.
560.502 of this chapter; and
(2) You make electronic submissions to BOEM through a secure
electronic filing system that conforms to the requirements of Sec.
560.500; or,
(b) You may file with BOEM a non-electronic document, containing a
corporate seal and the signature of an authorized person(s), attesting
that future documents and information filed by you by electronic or non-
electronic means will be legally binding without an affixed corporate
seal. If you file such a non-electronic attestation document with BOEM,
any requirement for use of a corporate seal under the regulations of
this chapter will be satisfied,

[[Page 459]]

and you will not need to affix your corporate seal to submissions where
they would have been otherwise required.
(c) If the State or territory in which you are incorporated does not
issue or require corporate seals, the document referred to in paragraphs
(a) and (b) of this section need not contain a corporate seal, but must
still contain the signature of the authorized person(s), a statement
that the State in which you are incorporated does not issue or require
corporate seals, and a statement that submissions made by you will be
legally binding.
(d) Any document, or information submitted without corporate seal
must still contain the signature of an individual qualified to sign who
has the requisite authority to act on your behalf.
(e) Any document or information submitted pursuant to this section
is submitted subject to the penalties of 18 U.S.C. 1001, as amended by
the False Statements Accountability Act of 1996.

Subpart B_Oil and Gas Five Year Leasing Program

Sec. 556.200 What is the Five Year leasing program?

Section 18(a) of OCSLA (43 U.S.C. 1344(a)), requires the Secretary
to prepare an oil and gas leasing program that consists of a five-year
schedule of proposed lease sales to best meet national energy needs,
showing the size, timing, and location of leasing activity as precisely
as possible. BOEM prepares the five year schedule of proposed lease
sales consistent with the principles set out in section 18(a)(1) and
(2)(A)-(H) of OCSLA (43 U.S.C. 1344(a)(1) and (2)(A)-(H)) to obtain a
proper balance among the potential for environmental damage, the
potential for the discovery of oil and gas, and the potential for
adverse impact on the coastal zone, as required by OCSLA section
18(a)(3) (43 U.S.C. 1344(a)(3)).

Sec. 556.201 Does BOEM consider multiple uses of the OCS?

BOEM gathers information about multiple uses of the OCS in order to
assist the Secretary in making decisions on the 5-year program pursuant
to provisions of 43 U.S.C. 1344. For this purpose, BOEM invites and
considers suggestions from States and local governments, industry, and
any other interested parties, primarily through public notice and
comment procedures. BOEM also invites and considers suggestions from
Federal agencies.

Sec. 556.202 How does BOEM start the Five Year program preparation process?

To begin preparation of the Five Year program, BOEM invites and
considers nominations for any areas to be included or excluded from
leasing, by doing the following:
(a) BOEM prepares and makes public official protraction diagrams and
leasing maps of OCS areas. In any area properly included in the official
Five Year diagrams and maps, any area not already leased for oil and gas
may be offered for lease.
(b) BOEM invites and considers suggestions and relevant information
from governors of States, local governments, industry, Federal agencies,
and other interested parties, through a publication of a request for
information in the Federal Register. Any local government must first
submit its comments on the request for information to its State governor
before sending the comments to BOEM.
(c) BOEM sends a letter to the governor of each affected State
asking the governor to identify specific laws, goals, and policies that
should be considered. Each State governor, as well as the Department of
Commerce, is requested to identify the relationship between any oil and
gas activity and the State under sections 305 and 306 of the CZMA, 16
U.S.C. 1454 and 1455.
(d) BOEM asks the Department of Energy for information on regional
and national energy markets and transportation networks.

Sec. 556.203 What does BOEM do before publishing a proposed Five Year program?

After considering the comments and information described in Sec.
556.202, BOEM will prepare a draft proposed Five Year program.
(a) At least 60 days before publication of a proposed program, BOEM
will send

[[Page 460]]

a letter, together with the draft proposed program, to the governor of
each affected State, inviting the governor to comment on the draft
proposed program.
(b) A governor, whether for purposes of preparing that State's
comments or otherwise, may solicit comments from local governments that
he determines may be affected by an oil and gas leasing program.
(c) If a governor's comments on the draft proposed program are
received by BOEM at least 15 days before submission of the proposed
program to Congress and its publication for comment in the Federal
Register, BOEM will reply to the governor in writing.

Sec. 556.204 How do governments and citizens comment on a proposed
Five Year program?

BOEM publishes the proposed program in the Federal Register for
comment by the public. At the same time, BOEM sends the proposed program
to the governors of the affected States and to Congress and the Attorney
General of the United States for review and comment.
(a) Governors are responsible for providing a copy of the proposed
program to affected local governments in their States. Local governments
may comment directly to BOEM, but must also send their comments to the
governor of their State.
(b) All comments from any party are due within 90 days after
publication of the request for comments in the Federal Register.

Sec. 556.205 What does BOEM do before approving a proposed final
Five Year program or a significant revision of a previously-approved
Five Year program?

At least 60 days before the Secretary may approve a proposed final
Five Year program or a significant revision to a previously approved
final Five Year program, BOEM will submit a proposed final program or
proposed significant revision to the President and Congress. BOEM will
also submit comments received and indicate the reasons why BOEM did or
did not accept any specific recommendation of the Attorney General of
the United States, the governor of a State, or the executive of a local
government.

Subpart C_Planning and Holding a Lease Sale

Sec. 556.300 What reports may BOEM and other Federal agencies prepare
before a lease sale?

For an oil and gas lease sale in a Five Year program, and as the
need arises for other mineral leasing pursuant to part 581 of this
chapter, BOEM will prepare a report describing the general geology and
potential mineral resources of the area under consideration. The
Director may request other interested Federal agencies to prepare
reports describing, to the extent known, any other valuable resources
contained within the general area and the potential effect of mineral
operations upon the resources or upon the total environment or other
uses of the area.

Sec. 556.301 What is a Call for Information and Nominations?

BOEM issues a Call for Information and Nominations (``Call'') on an
area proposed for leasing in the Five Year program through publication
in the Federal Register and other publications. A Call may include more
than one proposed sale. Comments are requested from industry and the
public on:
(a) Industry interest in the area proposed for leasing, including
nominations or indications of interest in specific blocks within the
area;
(b) Geological conditions, including bottom hazards;
(c) Archaeological sites on the seabed or near shore;
(d) Potential multiple uses of the proposed leasing area, including
navigation, recreation, and fisheries;
(e) Areas that should receive special concern and analysis; and
(f) Other socioeconomic, biological, and environmental information.

Sec. 556.302 What does BOEM do with the information from the Call?

(a) Based upon information and nominations received in response to
the Call, and in consultation with appropriate Federal agencies, the
Director will develop a recommendation of

[[Page 461]]

areas proposed for leasing for the Secretary for further consideration
for leasing and/or environmental analysis.
(1) In developing the recommendation, the Director will consider
available information concerning the environment, conflicts with other
uses, resource potential, industry interest, and other relevant
information, including comments received from State and local
governments and other interested parties in response to the Call.
(2) The Director, on his/her own motion, may include in the
recommendation areas in which interest has not been indicated in
response to a Call. In making a recommendation, the Director will
consider all available environmental information.
(3) Upon approval by the Secretary, the Director will announce the
area identified in the Federal Register.
(b) BOEM will evaluate the area(s) identified for further
consideration for the potential effects of leasing on the human, marine,
and coastal environments, and may develop measures to mitigate adverse
impacts, including lease stipulations, for the options to be analyzed.
The Director may hold public hearings on the environmental analysis
after an appropriate notice.
(c) BOEM will seek to inform the public, as soon as possible, of
changes from the area(s) proposed for leasing that occur after the Call
process.
(d) Upon request, the Director will provide relative indications of
interest in areas, as well as any comments filed in response to a Call
for a proposed sale. However, no information transmitted will identify
any particular area with the name of any particular party so as not to
compromise the competitive position of any participants in the process
of indicating interest.
(e) For supplemental sales provided for by Sec. 556.308, the
Director's recommendation will be replaced by a statement describing the
results of the Director's consideration of the factors specified above
in this section.

Sec. 556.303 What does BOEM do if an area proposed for leasing is within
three nautical miles of the seaward boundary of a coastal State?

For an area proposed for leasing that is within three nautical miles
of the seaward boundary of a coastal State, as governed by section
8(g)(1) of OCSLA (43 U.S.C. 1337(g)(1)):
(a) BOEM provides the governor of the coastal State, subject to the
confidentiality requirements in this chapter:
(1) A schedule for leasing; and
(2) An estimate of the potential oil and gas resources.
(b) At the request of the governor of a coastal State, BOEM will
provide to that governor, subject to the confidentiality requirements in
this chapter:
(1) Information concerning geographical, geological, and ecological
characteristics; and
(2) An identification of any field, geological structure, or trap,
or portion thereof, that lies within three nautical miles of the State's
boundary.

Sec. 556.304 How is a proposed notice of sale prepared?

(a) The Director will, in consultation with appropriate Federal
agencies, develop measures, including lease stipulations and conditions,
to mitigate adverse impacts on the environment, which will be contained,
or referenced, in the proposed notice of sale.
(b) A proposed notice of sale will be submitted to the Secretary for
approval. All comments and recommendations received and the Director's
findings or actions thereon, will also be forwarded to the Secretary.
(c) Upon approval by the Secretary, BOEM will send a proposed notice
of sale to the governors of affected States and publish the notice of
its availability in the Federal Register. The proposed notice of sale
references or provides a link to the lease form, and contains a
description of the area proposed for leasing, the proposed lease terms
and conditions of sale, and proposed stipulations to mitigate potential
adverse impacts on the environment.

[[Page 462]]

Sec. 556.305 How does BOEM coordinate and consult with States regarding
a proposed notice of sale?

(a) Within 60 days after receiving the proposed notice of sale,
governors of affected States may submit comments and recommendations to
BOEM regarding the size, timing, and location of the proposed sale.
Local governments may comment to BOEM directly, but must also send their
comments to the governor of their State.
(b) BOEM will provide a consistency determination under the Coastal
Zone Management Act (CZMA) (16 U.S.C. 1456) to each State with an
approved coastal zone management program that will determine whether the
proposed sale is consistent, to the maximum extent practicable, with the
enforceable policies of the State's approved coastal zone management
program.

Sec. 556.306 What if a potentially oil- or gas-bearing area underlies
both the OCS and lands subject to State jurisdiction?

(a) Whenever the Director or the governor of a coastal State
determines that a common potentially hydrocarbon-bearing area may
underlie the Federal OCS and State submerged lands, the Director or the
governor will notify the other party in writing of the determination.
(b) Thereafter the Director will provide to the governor of the
coastal State, subject to the confidentiality requirements in this
chapter:
(1) An identification of the areas proposed for leasing and a
schedule for, leasing; and
(2) An estimate of the oil and gas resources.
(c) At the request of the governor of the coastal State, the
Director will provide to such governor, subject to the confidentiality
requirements in this chapter:
(1) All geographical, geological, and ecological characteristics of
the areas proposed for leasing; and
(2) An identification of any field, geological structure, or trap
that lies within 3 miles of the State's seaward boundary.
(d) If BOEM intends to lease such blocks or tracts, the Director and
the governor of the coastal State may enter into an agreement for the
equitable disposition of the revenues from production of any common
potentially hydrocarbon-bearing area, pursuant to OCSLA section 8(g)(3)
(43 U.S.C. 1337(g)(3)). Any revenues received by the United States under
such an agreement are subject to the requirements of OSCLA section
8(g)(2) (43 U.S.C. 1337(g)(2)).
(e) If the Director and the governor do not enter into an agreement
under paragraph (d) of this section within 90 days, BOEM may
nevertheless proceed with the leasing of the tracts, in which case all
revenues will be deposited in a separate account in the Treasury of the
United States, pending disposition of 27% (twenty-seven percent) of the
revenues to the relevant coastal state(s), pursuant to the requirements
of OCSLA section 8(g)(2). (43 U.S.C. 1337(g)(2)).

Sec. 556.307 What does BOEM do with comments and recommendations received
on the proposed notice of sale?

(a) BOEM will consider all comments and recommendations received in
response to the proposed notice of sale.
(b) If the Secretary determines, after providing opportunity for
consultation, that a governor's comments, and those of any affected
local government, provide a reasonable balance between the national
interest and the well-being of the citizens of the State, the Secretary
will accept the recommendations of a State and/or local government(s).
Any such determination of the national interest will be based on the
findings, purposes and policies of the Act set forth in 43 U.S.C. 1332
and 43 U.S.C. 1801.
(c) BOEM will send to each governor written reasons for its
determination to accept or reject each governor's recommendation, and/or
to implement any alternative means to provide for a reasonable balance
between the national interest and the interests of the citizens of the
State.

Sec. 556.308 How does BOEM conduct a lease sale?

(a) BOEM publishes a final notice of sale in the Federal Register
and in

[[Page 463]]

other publications, as appropriate, at least 30 days before the date of
the sale. The final notice:
(1) States the place, time, and method for filing bids and the
place, date, and hour for opening bids; and
(2) Contains or references a description of the areas offered for
lease, the lease terms and conditions of sale, and stipulations to
mitigate potential adverse impacts on the environment.
(b) Oil and gas tracts are offered for lease by competitive sealed
bid in accordance with the terms and conditions in the final notice of
sale and applicable laws and regulations.
(c) Unless BOEM finds that a larger area is necessary for reasonable
economic production, no individual tract for oil and gas leasing will
exceed 5,760 acres in area. If BOEM finds that an area larger than 5,760
acres is necessary in any particular area, the size of any such tract
will be specified in the final notice of sale.
(d) The final notice of sale references, or provides a link to, the
OCS lease form which will be issued to successful bidders.

Sec. 556.309 Does BOEM offer blocks in a sale that is not on the Five Year
program schedule (called a Supplemental Sale)?

(a) Except as provided in paragraph (c) of this section, BOEM may
offer a block within a planning area included in the Five Year program
in an otherwise unscheduled sale, if the block:
(1) Received a bid that was rejected in an earlier sale;
(2) Had a high bid that was forfeited in a scheduled sale; or
(3) Is a development block subject to drainage.
(b) For an unscheduled sale, BOEM may disclose the classification of
the block as a development block.
(c) Blocks in the Central or Western Gulf of Mexico Planning Areas
cannot be offered in a sale that is not on the schedule.

Subpart D_Qualifications

Sec. 556.400 When must I demonstrate that I am qualified to hold
a lease on the OCS?

In order to bid on, own, hold, or operate a lease on the OCS,
bidders, record title holders, and operating rights owners must first
obtain a qualification number from BOEM.

Sec. 556.401 What do I need to show to become qualified to hold
a lease on the OCS and obtain a qualification number?

(a) You may become qualified to hold a lease on the OCS and obtain a
qualification number in accordance with Sec. 556.402, if you submit
evidence demonstrating that you are:
(1) A natural person who is a citizen or national of the United
States;
(2) A natural person who is an alien lawfully admitted for permanent
residence in the United States, as defined in 8 U.S.C. 1101(a)(20);
(3) A private, public, or municipal corporation or Limited Liability
Company or Limited Liability Corporation (either/both sometimes herein
referred to as ``LLC'') organized under the laws of any State of the
United States, the District of Columbia, or any territory or insular
possession subject to United States jurisdiction;
(4) An association of such citizens, nationals, resident aliens, or
corporations;
(5) A State, the District of Columbia, or any territory or insular
possession subject to United States jurisdiction;
(6) A political subdivision of a State, the District of Columbia, or
any territory or insular possession subject to United States
jurisdiction; or
(7) A Trust organized under the laws of any State of the United
States, the District of Columbia, or any territory or insular possession
subject to United States jurisdiction;
(b) Statements and evidence submitted to demonstrate qualification
under paragraphs (a)(1) through (6) of this section are subject to the
penalties of 18 U.S.C. 1001.
(b) BOEM may issue you a qualification number after you have
provided evidence acceptable to BOEM.

[[Page 464]]

Sec. 556.402 How do I make the necessary showing to qualify and obtain
a qualification number?

(a) If BOEM has already issued you a qualification number, you may
present that number to BOEM. If not, in order to become qualified, you
must provide the information in paragraph (b) or (c) of this section
before BOEM will issue you a BOEM qualification number.
(b) A natural person must be a citizen or national of the United
States, or a resident alien, to qualify. A United States citizen or
national must submit written evidence acceptable to BOEM attesting to
United States citizenship or national status. A resident alien must
submit an original or a photocopy of the United States Citizenship and
Immigration Services form evidencing legal status as a resident alien.
(c) A person who is not a natural person must submit evidence (refer
to paragraph (d) of this section) acceptable to BOEM that:
(1) It is authorized to conduct business under the laws of a State,
the District of Columbia, or any territory or insular possession subject
to United States jurisdiction under which it is organized;
(2) Under the operating rules of its business, it is authorized to
hold OCS leases; and
(3) Includes an up-to-date list of persons, and their titles, who
are authorized to bind the corporation, association or other entity when
conducting business on the OCS. It is up to you, in accordance with your
organizational structure or rules, to identify the individual, or group
of individuals, who has actual authority to bind your organization, and
the title(s) they will use when they sign documents to bind the
organization. You must maintain and regularly update the information as
to who has the authority to bind the organization whenever that
information changes.
(d) Acceptable evidence under paragraph (c) of this section
includes, but is not limited to:
(1) For a corporation,
(i) A statement by the Secretary of the corporation, over corporate
seal, certifying that the corporation is authorized to hold OCS leases;
and
(ii) Evidence of authority of holders of positions entitled to bind
the corporation, certified by Secretary of the corporation, over
corporate seal, such as:
(A) Certified copy of resolution of the board of directors with
titles of officers authorized to bind corporation;
(B) Certified copy of resolutions granting corporate officer
authority to issue a power of attorney; or
(C) Certified copy of power of attorney or certified copy of
resolution granting power of attorney.
(2) For a Limited or General Partnership,
(i) A statement by an authorized party certifying that the
partnership is authorized to hold OCS leases;
(ii) A copy of your signed partnership formation documents,
including a partnership agreement;
(iii) A statement from each partner indicating, as appropriate, U.S.
citizenship or incorporation or organization under the laws of a State,
the District of Columbia, or any territory or insular possession subject
to U.S. jurisdiction; and
(iv) Documentation evidencing the existence of the partnership and
that it was properly created, either from the Secretary of State of the
State in which the partnership is registered or by an equivalent State
or governmental office.
(3) For a Limited Liability Company or Limited Liability
Corporation,
(i) A certificate of formation of the LLC;
(ii) A statement by an individual authorized to bind the LLC, as
listed under (c)(4) above, certifying that the LLC is authorized to hold
OCS leases;
(iii) A statement from each member indicating, as appropriate, U.S.
citizenship, or incorporation or organization under the laws of a State,
the District of Columbia, or any territory or insular possession subject
to U.S. jurisdiction; and
(iv) Evidence of authority of holders of positions entitled to bind
the LLC, certified by an individual authorized to bind the LLC.
(4) For a Trust,
(i) A copy of the trust agreement or document establishing the trust
and all

[[Page 465]]

amendments, properly certified by the trustee; and
(ii) A statement indicating the law under which the trust is
established and that the trust is authorized to hold OCS leases.
(e) In the event that a person may be eligible to hold OCS leases,
but that type of person is not listed in paragraphs (c) or (d) of this
section, evidence of such eligibility will be submitted and certified by
the highest level of management of the person authorized to do so
pursuant to its operating agreement or governance documents.
(f) Any person who obtains a qualification number from BOEM is
responsible to ensure that it is not using the qualification number
approved by BOEM for any purpose that its operating rules do not allow.
(g) Any evidence submitted in response to paragraphs (c), (d), or
(e) of this section is submitted subject to 18 U.S.C. 1001.
(h) A person may not hold leases on the OCS until the evidence
requested in this section has been accepted and approved by BOEM and
BOEM has issued a qualification number to that person.
(i) If use of a corporate seal is required by this section, you may
meet the requirement as specified in Sec. 556.107.

Sec. 556.403 Under what circumstances may I be disqualified from acquiring
a lease or an interest in a lease on the OCS?

You may be disqualified from acquiring a lease or an interest in a
lease on the OCS if:
(a) You or your principals are excluded or disqualified from
participating in a transaction covered by Federal non-procurement
debarment and suspension (2 CFR parts 180 and 1400), unless the
Department explicitly approves an exception for a transaction pursuant
to the regulations in those parts;
(b) The Secretary finds, after notice and hearing, that you or your
principals (including in the meaning of ``you,'' for purposes of this
subparagraph, a bidder or prospective bidder) fail to meet due diligence
requirements or to exercise due diligence under section 8(d) of OCSLA
(43 U.S.C. 1337(d)) on any OCS lease; or
(c) BOEM disqualifies you from acquiring a lease or an interest in a
lease on the OCS based on your unacceptable operating performance. BOEM
will give you adequate notice and opportunity for a hearing before
imposing a disqualification, unless BSEE has already provided such
notice and opportunity for a hearing.

[81 FR 34275, May 31, 2016]

Sec. 556.404 What do the non-procurement debarment rules require that I do?

You must comply with the Department's non-procurement debarment
regulations at 2 CFR parts 180 and 1400.
(a) You must notify BOEM if you know that you or your principals are
excluded, disqualified, have been convicted or are indicted of a crime
as described in 2 CFR part 180, subpart C. You must make this
notification before you sign a lease, sublease, or an assignment of
record title interest or operating rights interest, or become a lease or
unit operator. This paragraph does not apply if you have previously
provided a statement disclosing this information, and you have received
an exception from the Department, as described in 2 CFR 180.135 and 2
CFR 1400.137.
(b) If you wish to enter into a covered transaction with another
person at a lower tier, as described in 2 CFR 180.200, you must first:
(1) Verify that the person is not excluded or disqualified under 2
CFR part 180; and
(2) Require the person to:
(i) Comply with 2 CFR part 180, subpart C; and
(ii) Include the obligation to comply with 2 CFR part 180, subpart C
in its contracts and other transactions.
(c) After you enter into a covered transaction, you must immediately
notify BOEM in writing if you learn that:
(1) You failed to disclose pertinent information earlier; or
(2) Due to changed circumstances, you or your principals now meet
any of the criteria in 2 CFR 180.800.

[[Page 466]]

Sec. 556.405 When must I notify BOEM of mergers, name changes,
or changes of business form?

You must notify BOEM of any merger, name change, or change of
business form as soon as practicable, but in no case later than one year
after the earlier of the effective date or the date of filing the change
or action with the Secretary of State or other authorized official in
the State of original registry.

Subpart E_Issuance of a Lease

How To Bid

Sec. 556.500 Once qualified, how do I submit a bid?

(a) You must submit a separate sealed bid for each tract or bidding
unit to the address provided and by the time specified in the final
notice of sale. You may not bid on less than an entire tract or bidding
unit.
(b) BOEM requires a deposit for each bid. The final notice of sale
will specify the amount and method of payment.
(c) Unless otherwise specified in the final notice of sale, the bid
deposit amount will be 20 percent of the amount of the bid for any given
tract or bidding unit.
(d) You may not submit a bid on an OCS tract if, after notice and
hearing under section 8(d) of OCSLA (43 U.S.C. 1337(d)), the Secretary
finds that you are not meeting the diligence requirements on any OCS
lease.
(e) If the authorized officer within BOEM rejects your high bid, the
decision is final for the Department, subject only to reconsideration
upon your written request as set out in Sec. 556.517.

Sec. 556.501 What information do I need to submit with my bid?

In accordance with OCSLA section 18(a)(4) (43 U.S.C. 1344(a)(4)),
BOEM must evaluate every bid to ensure that the federal government
receives fair market value for every lease. Section 26(a)(1)(A) of OCSLA
(43 U.S.C. 1352(a)(1)(A)) provides that, in accordance with regulations
prescribed by the Secretary, any lessee or permittee conducting any
exploration for, or development or production of, oil or gas must
provide the Secretary access to all data and information (including
processed, analyzed, and interpreted information) obtained from that
activity and must provide copies of that data and information as the
Secretary may request.
(a) As part of the lease sale process, every bidder submitting a bid
on a tract, or participating as a joint bidder in such a bid, may at the
time of bid be required to submit various information, including a
Geophysical Data and Information Statement (GDIS) corresponding to that
tract, as well as the bidder's exclusive/proprietary geophysical data in
order for BOEM to properly evaluate the bid. If a GDIS required, each
GDIS must include, as required by Sec. 551.12(b) and (c) of this
chapter:
(1) A list of geophysical surveys or other information used as part
of the decision to bid or participate in a bid on the block.
(2) An accurate and complete record of each geophysical survey
conducted, including digital navigational data and final location maps.
The bidder and any joint bidder must include a map for each survey
identified in the GDIS that illustrates the actual areal extent of the
proprietary geophysical data.
(b) If a bidder is required to submit a GDIS, the GDIS must be
submitted even if the bidder did not rely on proprietary geophysical
data and information in deciding to bid or participate as a joint bidder
in the bid for any particular block, and must include entries for all
such blocks.
(c) The bidder must submit each GDIS in a separate and sealed
envelope, or in an electronically readable spreadsheet format, with
proprietary seismic data maps also available in an electronic format.
Each bidder must submit the GDIS even if its joint bidder or bidders on
a specific block also have submitted a GDIS.
(d) If BOEM requires additional information related to bidding, it
will describe the additional information requirements in the final
notice of sale.
(e) BOEM will reimburse bidders for the costs of complying with the
requirements of this section, in accordance with Sec. 550.196 (on
lease) and/or Sec. 551.13 (off lease) of this chapter.

[[Page 467]]

(f) Bids that are not made in compliance with this section will be
considered incomplete and invalid.

Restrictions on Joint Bidding

Sec. 556.511 Are there restrictions on bidding with others
and do those restrictions affect my ability to bid?

The Energy Policy and Conservation Act of 1975, 42 U.S.C. 6213,
prohibits joint bidding by major oil and gas producers under certain
circumstances. BOEM implements 42 U.S.C. 6213 as follows:
(a) BOEM publishes twice yearly in the Federal Register a restricted
joint bidders list. A person appearing on this list is limited in its
ability to submit a joint bid. The list:
(1) Consists of the persons chargeable with an average worldwide
daily production in excess of 1.6 million barrels of crude oil and/or
its equivalent in natural gas liquids and natural gas for the prior
production period; and
(2) Is based upon the statement of production that filed as required
by Sec. 556.513.
(b) If BOEM places you on the restricted joint bidders list, BOEM
will send you a copy of the order placing you on the list. You may
appeal this order to the Interior Board of Land Appeals under 30 CFR
part 590, subpart A.
(c) If you are listed in the Federal Register in any group of
restricted bidders, you may not bid:
(1) Jointly with another person in any other group of restricted
bidders for the applicable 6-month bidding period; or
(2) Separately during the 6-month bidding period if you have an
agreement with another restricted bidder that will result in joint
ownership in an OCS lease.
(d) If you are listed in the Federal Register in any group of
restricted bidders, you may not make any pre-bidding agreement for the
conveyance of any potential lease interest, whether by assignment, sale,
transfer, or other means, to any person on the list of restricted joint
bidders.
(e) Even if you are not listed in the Federal Register in any group
of restricted bidders, you are prohibited from making any pre-bidding
agreement for the assignment, sale, transfer, or other conveyance of any
potential lease interest to two or more persons in different groups on
the list of restricted joint bidders.
(f) As a bidder, you are prohibited from unlawful combination with,
or intimidation of, bidders under 18 U.S.C. 1860.

Sec. 556.512 What bids may be disqualified?

The following bids for any oil and gas lease will be disqualified
and rejected in their entirety:
(a) A joint bid submitted by two or more persons who are on the
effective List of Restricted Joint Bidders; or
(b) A joint bid submitted by two or more persons when:
(1) One or more of those persons is chargeable for the prior
production period with an average daily production in excess of 1.6
million barrels of crude oil, natural gas and natural gas liquids and
has not filed a Statement of Production, as required by Sec. 556.513 of
this part for the applicable 6-month bidding period, or
(2) Any of those persons have failed or refused to file a detailed
report of production when required to do so under Sec. 556.513, or
(c) A single or joint bid submitted pursuant to an agreement
(whether written or oral, formal or informal, entered into or arranged
prior to or simultaneously with the submission of such single or joint
bid, or prior to or simultaneously with the award of the bid upon the
tract) that provides:
(1) For the assignment, transfer, sale, or other conveyance of less
than a 100 percent interest in the entire tract on which the bid is
submitted, by a person or persons on the List of Restricted Joint
Bidders, effective on the date of submission of the bid, to another
person or persons on the same List of Restricted Joint Bidders; or
(2) For the assignment, sale, transfer or other conveyance of less
than a 100 percent interest in any fractional interest in the entire
tract (which fractional interest was originally acquired by the person
making the assignment, sale, transfer or other conveyance, under the
provisions of the act) by a person or persons on the List of Restricted
Joint Bidders, effective on the

[[Page 468]]

date of submission of the bid, to another person or persons on the same
List of Restricted Joint Bidders; or
(3) For the assignment, sale, transfer, or other conveyance of any
interest in a tract by a person or persons not on the List of Restricted
Joint Bidders, effective on the date of submission of the bid, to two or
more persons on the same List of Restricted Joint Bidders; or
(4) For any of the types of conveyances described in paragraphs
(c)(1), (2), or (3) of this section where any party to the conveyance is
chargeable for the prior production period with an average daily
production in excess of 1.6 million barrels of crude oil, natural gas
and natural gas liquids and has not filed a Statement of Production
pursuant to Sec. 556.513 for the applicable six-month bidding period.
Assignments expressly required by law, regulation, lease or lease
stipulation will not disqualify an otherwise qualified bid; or
(d) A bid submitted by or in conjunction with a person who has filed
a false, fraudulent or otherwise intentionally false or misleading
detailed Report of Production.

Sec. 556.513 When must I file a statement of production?

(a) You must file a statement of production if your average
worldwide daily production exceeded 1.6 million barrels for the prior
production period, as determined using the method set forth in Sec.
556.514. Your statement of production must specify that you were
chargeable with an average daily production in excess of 1.6 million
barrels for the prior production period.
(b) The prior production periods are as follows:

------------------------------------------------------------------------
The prior production period
For the bidding period of is the preceding
------------------------------------------------------------------------
(1) May through October................... July through December.
(2) November through April................ January through June.
------------------------------------------------------------------------

------------------------------------------------------------------------
You must file the statement
For the bidding period of by
------------------------------------------------------------------------
(1) May through October................... March 17.
(2) November through April................ September 17.
------------------------------------------------------------------------

(d) If you are required to file a statement of production, BOEM may
require you to submit a detailed report of production.
(1) The detailed report of production must list crude oil, natural
gas liquids, and natural gas produced worldwide from reservoirs during
the prior production period, and therefore chargeable to the prior
production period.
(i) The amount of crude oil chargeable to the prior production
period will be established by measurement of volumes delivered at the
point of custody transfer (e.g., from storage tanks to pipelines,
trucks, tankers, or other media for transport to refineries or
terminals), with adjustments for net differences between opening and
closing inventories, and basic sediment and water.
(ii) The amount of natural gas liquids chargeable to the prior
production period must include gas liquefied at surface separators,
field facilities, or gas processing plants.
(iii) The amount of natural gas chargeable to the prior production
period must include adjustments, where applicable, to reflect the volume
of gas returned to natural reservoirs, and the reduction of volume
resulting from the removal of natural gas liquids and non-hydrocarbon
gases.
(2) You must submit the detailed report of production within 30 days
after receiving BOEM's request.
(3) BOEM may inspect and copy any document, record of production,
analysis, and other material to verify the accuracy of any earlier
statement of production.
(e) If you submit a statement of production that misrepresents your
chargeable production, the Department may cancel any lease awarded in
reliance upon the statement.

Sec. 556.514 How do I determine my production for purposes
of the restricted joint bidders list?

(a) To determine the amount of production chargeable to you, add
together:
(1) Your average daily production in barrels of crude oil, natural
gas liquids, and natural gas worldwide, all measured at 60 [deg]F, using
the equivalency or

[[Page 469]]

conversion factors for natural gas liquids and natural gas set out in 42
U.S.C. 6213(b)(2) and (3); and
(2) Your proportionate share of the average daily production owned
by any person that has an interest in you and/or in which you have an
interest.
(b) For the purpose of paragraph (a)(1) of this section, your
production includes 100 percent of production owned by:
(1) You;
(2) Every subsidiary of yours;
(3) Every person of which you are a subsidiary; and
(4) Every subsidiary of any person of which you are a subsidiary.
(c) For purposes of paragraph (a)(2) of this section, interest means
at least a five percent ownership or control of you or the reporting
person and includes any interest:
(1) From ownership of securities or other evidence of ownership; or,
(2) By participation in any contract, agreement, or understanding
regarding control of the person or their production of crude oil,
natural gas liquids, or natural gas.
(d) For purposes of this section, subsidiary means a person, 50
percent or more of whose stock or other interest having power to vote
for the election of a controlling body, such as directors or trustees,
is directly or indirectly owned or controlled by another person.
(e) For purposes of this section, production chargeable to you
includes, but is not limited to, production obtained as a result of a
production payment or a working, net profit, royalty, overriding
royalty, or carried interest.
(f) For purposes of this section, production must be measured with
appropriate adjustments for:
(1) Basic sediment and water;
(2) Removal of natural gas liquids and non-hydrocarbon gases; and
(3) Volume of gas returned to natural reservoirs.

Sec. 556.515 May a person be exempted from joint bidding restrictions?

BOEM may exempt you from some or all of the reporting requirements
listed in Sec. 556.513, and/or some or all of the joint bidding
restrictions listed in Sec. Sec. 556.511 and/or 556.512(a), (b), and/or
(c), if, after opportunity for a hearing, BOEM determines that the
extremely high costs in an area will preclude exploration and
development without an exemption.

How Does BOEM Act on Bids?

Sec. 556.516 What does BOEM do with my bid?

(a) BOEM opens the sealed bids at the place, date, and hour
specified in the final notice of sale for the sole purpose of publicly
announcing and recording the bids. BOEM does not accept or reject any
bids at that time.
(b) BOEM reserves the right to reject any and all bids received,
regardless of the amount offered. BOEM accepts or rejects all bids
within 90 days of opening. BOEM reserves the right to extend that time
if necessary, and in that event, BOEM will notify bidder(s) in writing
prior to the expiration of the initial 90-day period, or of any
extension. Any bid not accepted within the prescribed 90-day period, or
any extension thereof, will be deemed rejected. If your bid is rejected,
BOEM will refund any money deposited with your bid, plus any interest
accrued.
(c) If the highest bids are a tie, BOEM will notify the bidders who
submitted the tie bids. Within 15 days after notification, those
bidders, if qualified, and not otherwise prohibited from bidding
together, may:
(1) Agree to accept the lease jointly. The bidders must notify BOEM
of their decision and submit a copy of their agreement to accept the
lease jointly.
(2) Agree between/among themselves which bidder will accept the
lease. The bidders must notify BOEM of their decision.
(d) If no agreement is submitted pursuant to paragraph (c) of this
section, BOEM will reject all the tie bids.
(e) The Attorney General, in consultation with the Federal Trade
Commission, has 30 days to review the results of the lease sale before
BOEM may accept the bid(s) and issue the lease(s).

Sec. 556.517 What may I do if my high bid is rejected?

(a) The decision of the authorized officer on bids is the final
action of the

[[Page 470]]

Department, subject only to reconsideration of the rejection of the high
bid by the Director, in accordance with paragraph (b) of this section.
(b) Within 15 days of bid rejection, you may file a written request
for reconsideration with the Director, with a copy to the authorized
officer. Such request must provide evidence as to why the Director
should reconsider your bid. You will receive a written response either
affirming or reversing the rejection of your bid.
(c) The Director's decision on the request for reconsideration is
not subject to appeal to the Interior Board of Land Appeals in the
Department's Office of Hearings and Appeals.

Awarding the Lease

Sec. 556.520 What happens if I am the successful high bidder
and BOEM accepts my bid?

(a) If BOEM accepts your bid, BOEM will provide you with the
appropriate number of copies of the lease for you to execute and return
to BOEM. Within 11 business days after you receive the lease copies, you
must:
(1) Execute all copies of the lease;
(2) Pay the first year's rental;
(3) Pay the balance of the bonus bid, unless deferred under
paragraph (b) below;
(4) Comply with subpart I of this part; and,
(5) Return all copies of the executed lease, including any required
bond or other form of security approved by the Regional Director, to
BOEM.
(b) If provided for in the final notice of sale, BOEM may defer any
part of the bonus and bid payment for up to five years after the sale
according to a schedule included in the final notice of sale. You must
provide a bond acceptable to BOEM to guarantee payment of a deferred
bonus bid.
(c) If you do not make the required payments and execute and return
all copies of the lease and any required bond within 11 business days
after receipt, or if you otherwise fail to comply with applicable
regulations, your deposit will be forfeited. However, BOEM will return
any deposit with interest if the tract is withdrawn from leasing before
you execute the lease.
(d) If you use an agent to execute the lease, you must include
evidence with the executed copies of the lease that a person who is on
the list of persons referenced in Sec. 556.402(c)(3) authorized the
agent to act for you.
(e) After you comply with all requirements in this section, and
after BOEM has executed the lease, BOEM will send you a fully executed
lease.

Sec. 556.521 When is my lease effective?

Your lease is effective on the first day of the month following the
date that BOEM executes the lease. You may request in writing, before
BOEM executes the lease, that your lease be effective as of the first
day of the month in which BOEM executes the lease. If BOEM agrees to
make the lease effective as of the earlier date, BOEM will so indicate
when it executes the lease.

Sec. 556.522 What are the terms and conditions of the lease
and when are they published?

The terms and conditions of the lease will be stated in the final
notice of sale and contained in the lease instrument itself. Oil and gas
leases and leases for sulfur will be issued on forms approved by the
Director.

Subpart F_Lease Term and Obligations

Length of Lease

Sec. 556.600 What is the primary term of my oil and gas lease?

(a) The primary term of an oil and gas lease will be five years,
unless BOEM determines that:
(1) The lease is located in unusually deep water or involves other
unusually adverse conditions; and,
(2) A lease term longer than five years is necessary to explore and
develop the lease.
(b) If BOEM determines that the criteria in paragraphs (a)(1) and
(2) of this section are met, it may specify a longer primary term, not
to exceed 10 years.
(c) BOEM will specify the primary term in the final notice of sale
and in the lease instrument.

[[Page 471]]

(d) The lease will expire at the end of the primary term, unless
maintained beyond that term in accordance with the provisions of Sec.
556.601.

Sec. 556.601 How may I maintain my oil and gas lease beyond the primary term?

You may maintain your oil and gas lease beyond the expiration of the
primary term as long as:
(a) You are producing oil or gas in paying quantities;
(b) You are conducting approved drilling or well reworking
operations with the objective of establishing production in paying
quantities, in accordance with 30 CFR 250.180;
(c) You are producing from, or drilling or reworking, an approved
well adjacent to or adjoining your lease that extends directionally into
your lease in accordance with 30 CFR 256.71;
(d) You make compensatory payments on your lease in accordance with
30 CFR 256.72;
(e) Your lease is included in a BSEE-approved unit, in accordance
with 30 CFR part 250, subpart M; or
(f) Your lease is subject to a suspension of production or a
suspension of operations, in accordance with 30 CFR 250.168 through
250.180, for reasons other than gross negligence or a willful violation
of a provision of your lease or any governing regulations.

Sec. 556.602 What is the primary term of my sulfur lease?

(a) Your sulfur lease will have a primary term of not more than 10
years, as specified in the lease.
(b) BOEM will announce the primary term prior to the lease sale.
(c) The lease will expire at the end of the primary term unless
maintained beyond that term in accordance with the provisions of Sec.
556.603.

Sec. 556.603 How may I maintain my sulfur lease beyond the primary term?

You may maintain your sulfur lease after the primary term as long as
you are producing sulfur in paying quantities, conducting drilling, well
reworking or plant construction, or other operations for the production
of sulfur or you are granted a suspension by BSEE; or your lease is
subject to a suspension directed by BSEE for reasons other than gross
negligence or a willful violation of a provision of your lease or
governing regulations.

Lease Obligations

Sec. 556.604 What are my rights and obligations as a record title owner?

(a) As a record title owner, you are responsible for all
administrative and operating performance on the lease, including paying
any rent and royalty due.
(b)(1) A record title owner owns operating rights to the lease,
unless and until he or she severs the operating rights by subleasing
them to someone else.
(2) A sublease of operating rights from record title may be for a
whole or undivided fractional interest in the entire lease or a
described aliquot portion of the lease and/or a depth interval. The
sublease creates an operating rights interest in the sublessee, herein
referred to as the operating rights owner.
(c) Within any given aliquot, the record title owner may sublease
operating rights for up to a maximum of two depth divisions, which may
result in a maximum of three different depth intervals. But, if the one,
or two, depth divisions to which operating rights are subleased do not
include the entire depth of the lease, whatever depth division(s) has
not been subleased, remains part of the lessee/sublessor's record title
interest. The depth intervals for which operating rights are subleased
must be defined by a beginning and ending depth and the ending of one
depth level must abut the beginning of the next depth level, with no gap
in between.
(d) Every current and prior record title owner is jointly and
severally liable, along with all other record title owners and all prior
and current operating rights owners, for compliance with all non-
monetary terms and conditions of the lease and all regulations issued
under OCSLA, as well as for fulfilling all non-monetary obligations,
including decommissioning obligations, which accrue while it holds
record title interest.

[[Page 472]]

(e) Record title owners that acquired their record title interests
through assignment from a prior record title owner are also responsible
for remedying all existing environmental or operational problems on any
lease in which they own record title interests, with subrogation rights
against prior lessees.
(f) For monetary obligations, your obligation depends on the source
of the monetary obligation and whether you have retained or severed your
operating rights.
(1) With respect to those operating rights that you have retained,
you are primarily liable under 30 U.S.C. 1712(a) for your pro-rata share
of all other monetary obligations pertaining to that portion of the
lease subject to the operating rights you have retained, based on your
share of operating rights in that portion of the lease.
(2) With respect to all monetary obligations arising from or in
connection with those operating rights that have been severed from your
record title interest, your obligation is secondary to that of the
sublessee(s) or later assignee(s) of the operating rights that were
severed from your record title interest, as prescribed in 30 U.S.C.
1712(a).

Sec. 556.605 What are my rights and obligations as an operating rights owner?

(a) As an operating rights owner, you have the right to enter the
leased area to explore for, develop, and produce oil and gas resources,
except helium gas, contained within the aliquot(s) and depths within
which you own operating rights, according to the lease terms, applicable
regulations, and BOEM's approval of the sublease or subsequent
assignment of the operating rights.
(b) Unless otherwise prohibited, you have the right to authorize
another party to conduct operations on the part of the lease to which
your operating rights appertain.
(c) An owner of operating rights who is designating a new designated
operator must file a designation of operator under Sec. 550.143 of this
chapter.
(d) An operating rights owner is only liable for obligations arising
from that portion of the lease to which its operating rights appertain
and that accrue during the period in which the operating rights owner
owned the operating rights.
(e) You are jointly and severally liable with other operating rights
owners and the record title owners for all non-monetary lease
obligations pertaining to that portion of the lease subject to your
operating rights, which accrued during the time you held your operating
rights interest.
(f) An operating rights owner that acquires its operating rights
interests through assignment from a prior operating rights owner is also
responsible, with subrogation rights against prior operating rights
owners, for remedying existing environmental or operational problems, to
the extent that such problems arise from that portion of the lease to
which its operating rights appertain, on any lease in which it owns
operating rights.
(g) You are primarily liable for monetary obligations pertaining to
that portion of the lease subject to your operating rights, and the
record title owners are secondarily liable. If there is more than one
operating rights owner in a lease, each operating rights owner is
primarily liable for its pro-rata share of the monetary obligations that
pertain to the portion of the lease that is subject to its operating
rights.

Helium

Sec. 556.606 What must a lessee do if BOEM elects to extract helium
from a lease?

(a) BOEM reserves the ownership of, and the right to extract, helium
from all gas produced from your OCS lease. Under section 12(f) of OCSLA
(43 U.S.C. 1341(f)), upon our request, you must deliver all or a
specified portion of the gas containing helium to BOEM at a point on the
leased area or at an onshore processing facility that BOEM designates.
(b) BOEM will determine reasonable compensation and pay you for any
loss caused by the extraction of helium, except for the value of the
helium itself. BOEM may erect, maintain, and operate on your lease any
reduction work and other equipment necessary for helium extraction. Our
extraction of helium will be conducted in a manner to

[[Page 473]]

not cause substantial delays in the delivery of gas to your purchaser.

Subpart G_Transferring All or Part of the Record Title Interest in a
Lease

Sec. 556.700 May I assign or sublease all or any part of the record title
interest in my lease?

(a) With BOEM approval, you may assign your whole, or a partial
record title interest in your entire lease, or in any aliquot(s)
thereof.
(b) With BOEM approval, you may sever all, or a portion of, your
operating rights.
(c) You must request approval of each assignment of a record title
interest and each sublease of an operating rights interest. Each
instrument that transfers a record title interest must describe, by
aliquot parts, the interest you propose to transfer. Each instrument
that severs an operating rights interest must describe, by officially
designated aliquot parts and depth levels, the interest proposed to be
transferred.

Sec. 556.701 How do I seek approval of an assignment of the record title
interest in my lease, or a severance of operating rights
from that record title interest?

(a) The Regional Director will provide the form to record an
assignment of record title interest in a Federal OCS oil and gas or
sulfur lease, or a severance of operating rights from that record title
interest. You must submit to BOEM two originals of each instrument that
transfers ownership of record title within 90 days after the last party
executes the transfer instrument. You must pay the service fee listed in
Sec. 556.106 with your request and your submission must include
evidence of payment via pay.gov.
(b) Before BOEM approves an assignment or transfer, it must consult
with, and consider the views of, the Attorney General. The Secretary may
act on an assignment or transfer if the Attorney General has not
responded to a request for consultation within 30 days of said request.
(c) A new record title owner or sublessee must file a designation of
operator, in accordance with Sec. 550.143 of this chapter, along with
the request for the approval of the assignment.

Sec. 556.702 When will my assignment result in a segregated lease?

(a) When there is an assignment by all record title owners of 100
percent of the record title to one or more aliquots in a lease, the
assigned and retained portions become segregated into separate and
distinct leases. In such case, both the new lease and the remaining
portion of the original lease are referred to as ``segregated leases''
and the assignee(s) becomes the record title owner(s) of the new lease,
which is subject to all the terms and conditions of the original lease.
(b) If a record title holder transfers an undivided interest, i.e.,
less than 100 percent of the record title interest in any given
aliquot(s), that transfer will not segregate the portions of the
aliquots, or the whole aliquots, in which part of the record title was
transferred, into separate leases from the portion(s) in which no
interest was transferred. Instead, that transfer will create a joint
ownership between the assignee(s) and assignor(s) in the portions of the
lease in which part of the record title interest was transferred. Any
transfer of an undivided interest is subject to approval by BOEM.

Sec. 556.703 What is the effect of the approval of the assignment
of 100 percent of the record title in a particular aliquot(s)
of my lease and of the resulting lease segregation?

(a) The bonding/financial assurance requirements of subpart I of
this part apply separately to each segregated lease.
(b) The royalty, minimum royalty, and rental provisions of the
original lease will apply separately to each segregated lease.
(c) BOEM will allocate among the segregated leases, on a basis that
is equitable under the circumstances, any remaining unused royalty
suspension volume or other form of royalty suspension or royalty relief
that had been granted to the original lease, not to exceed in aggregate
the total remaining amount.
(d) Each segregated lease will continue in full force and effect for
the

[[Page 474]]

primary term of the original lease and so long thereafter as each
segregated lease meets the requirements outlined in Sec. 556.601. A
segregated lease that does not meet the requirements of Sec. 556.601
does not continue in force even if another segregated lease, which was
part of the original lease, continues to meet those requirements.

Sec. 556.704 When would BOEM disapprove an assignment or sublease
of an interest in my lease?

(a) BOEM may disapprove an assignment or sublease of all or part of
your lease interest(s):
(1) When the transferor or transferee has unsatisfied obligations
under this chapter or 30 CFR chapters II or XII;
(2) When a transferor attempts a transfer that is not acceptable as
to form or content (e.g., not on standard form, containing incorrect
legal description, not executed by a person authorized to bind the
corporation, transferee does not meet the requirements of Sec. 556.401,
etc.); or,
(3) When the transfer does not conform to these regulations, or any
other applicable laws or regulations (e.g., departmental debarment
rules).
(b) A transfer will be void if it is made pursuant to any prelease
agreement that would cause a bid to be disqualified, such as those
described in Sec. 556.511(c), (d), or (e).

Sec. 556.705 How do I transfer the interest of a deceased natural person
who was a lessee?

(a) An heir or devisee must submit evidence by means of a certified
copy of an appropriate court order or decree that the person is
deceased; or, if no court action is necessary, a certified copy of the
will and death certificate or notarized affidavits of two disinterested
parties with knowledge of the facts.
(b) The heir or devisee, if the lawful successor in interest, must
submit evidence that he/she is the person named in the will or evidence
from an appropriate judgment of a court or decree that he/she is the
lawful successor in interest, along with the required evidence of his/
her qualifications to hold a lease under subpart D of this part.
(c) If the heir or devisee does not qualify to hold a lease under
subpart D of this part, he/she will be recognized as the successor in
interest, but he/she must divest him/herself of this interest in the
lease, to a person qualified to be a hold a lease, within two years.

Sec. 556.706 What if I want to transfer record title interests
in more than one lease at the same time, but to different parties?

You may not transfer interests in more than one lease to different
parties using the same instrument. If you want to transfer the interest
in more than one lease at the same time, you must submit duplicate,
originally executed forms for each transfer. The forms used for each
transfer must be accompanied by a cover letter executed by one of the
parties to the transfer (or an authorized agent thereof) and evidence of
payment via pay.gov.

Sec. 556.707 What if I want to transfer different types of lease interests
(not only record title interests) in the same lease to different parties?

You may not transfer different types of lease interests in a lease
to different parties using the same instrument. You must submit
duplicate, originally executed forms for each transfer, to a different
party, of a different type of lease interest. The form used to transfer
each type of lease interest must be accompanied by a cover letter
executed by one of the parties to the transfer (or an authorized agent
thereof) and evidence of payment via pay.gov.

Sec. 556.708 What if I want to transfer my record title interests
in more than one lease to the same party?

You may not transfer your record title interests in more than one
lease to the same party using the same instrument. If you want to
transfer record title interests in more than one lease at the same time,
you must submit separate, originally executed forms for each transfer.
The forms used for each transfer must be accompanied by a cover letter
executed by one of the parties to the transfer (or an authorized agent
thereof), and evidence of payment via pay.gov. A separate fee applies to
each individual transfer of interest.

[[Page 475]]

Sec. 556.709 What if I want to transfer my record title interest
in one lease to multiple parties?

You may transfer your record title interest in one lease to multiple
parties using the same instrument. That instrument must be submitted in
duplicate originals, accompanied by a cover letter executed by one of
the parties to the transfer (or an authorized agent thereof). In such a
multiple transfer of interests using a single instrument, a separate fee
applies to each individual transfer of interest, and evidence of payment
via pay.gov must accompany the instrument.

Sec. 556.710 What is the effect of an assignment of a lease
on an assignor's liability under the lease?

If you assign your record title interest, as an assignor you remain
liable for all obligations, monetary and non-monetary, that accrued in
connection with your lease during the period in which you owned the
record title interest, up to the date BOEM approves your assignment.
BOEM's approval of the assignment does not relieve you of these accrued
obligations. Even after assignment, BOEM or BSEE may require you to
bring the lease into compliance if your assignee or any subsequent
assignee fails to perform any obligation under the lease, to the extent
the obligation accrued before approval of your assignment. Until there
is a BOEM-approved assignment of interest, you, as the assignor, remain
liable for the performance of all lease obligations that accrued while
you held record title interest, until all such obligations are
fulfilled.

Sec. 556.711 What is the effect of a record title holder's sublease
of operating rights on the record title holder's liability?

(a) A record title holder who subleases operating rights remains
liable for all obligations of the lease, including those obligations
accruing after BOEM's approval of the sublease, subject to Sec.
556.604(e) and (f).
(b) Neither the sublease of operating rights, nor subsequent
assignment of those rights by the original sublessee, nor by any
subsequent assignee of the operating rights, alters in any manner the
liability of the record title holder for nonmonetary obligations.
(c) Upon approval of the sublease of the operating rights, the
sublessee and subsequent assignees of the operating rights become
primarily liable for monetary obligations, but the record title holder
remains secondarily liable for them, as prescribed in 30 U.S.C. 1712(a)
and Sec. 556.604(f)(2).

Sec. 556.712 What is the effective date of a transfer?

Any transfer is effective at 12:01 a.m. on the first day of the
month following the date on which BOEM approves your request, unless you
request an earlier effective date and BOEM approves that earlier date,
but such earlier effective date, if prior to the date of BOEM's
approval, does not relieve you of obligations accrued between that
earlier effective date and the date of approval.

Sec. 556.713 What is the effect of an assignment of a lease
on an assignee's liability under the lease?

As assignee, you and any subsequent assignees are liable for all
obligations that accrue after the effective date of your assignment. As
assignee, you must comply with all the terms and conditions of the lease
and regulations issued under OCSLA, and in addition, you must remedy all
existing environmental and operational problems on the lease, properly
abandon all wells, and reclaim the site, as required under 30 CFR part
250.

Sec. 556.714 As a restricted joint bidder, may I transfer an interest
to another restricted joint bidder?

(a) Where the proposed assignment or transfer is by a person who, at
the time of acquisition of an interest in the lease, was on the List of
Restricted Joint Bidders, and that assignment or transfer is of less
than the entire interest held by the assignor or transferor and to a
person or persons on the same List of Restricted Joint Bidders, the
assignor or transferor must file, prior to the approval of the
assignment, a copy of all agreements applicable to the acquisition of
that lease or fractional interest, or a description of the timing and
nature of the agreement(s)

[[Page 476]]

by which the assignor or transferor acquired the interest it now wishes
to transfer.
(b) Such description of the timing and nature of the transfer
agreement must be submitted together with a certified statement that
attests to the truth and accuracy of any information reported concerning
that agreement, subject to the penalties of 18 U.S.C. 1001.
(c) If you wish to transfer less than your entire interest to
another restricted joint bidder, BOEM may request the opinion of the
Attorney General before acting on your request.
(d) You may request that any submission to BOEM made pursuant to
this part be treated confidentially. Please note such a request on your
submission. BOEM will treat this request for confidentiality in
accordance with the regulations at Sec. 556.104 and the regulations at
43 CFR part 2.

Sec. 556.715 Are there any interests I may transfer or record
without BOEM approval?

(a) You may create, transfer, or assign economic interests without
BOEM approval. However, for record purposes, you must send BOEM a copy
of each instrument creating or transferring such interests within 90
days after the last party executes the transfer instrument. For each
lease affected, you must pay the service fee listed in Sec. 556.106
with your documents submitted for record purposes and your submission
must include evidence of payment via pay.gov.
(b) For recordkeeping purposes, you may also submit other legal
documents to BOEM for transactions that do not require BOEM approval. If
you submit such documents for record purposes not required by this part,
you must pay the service fee listed in Sec. 556.106 with your document
submissions for each lease affected. Your submission must include
evidence of payment via pay.gov.

Sec. 556.716 What must I do with respect to the designation of operator
on a lease when a transfer of record title is submitted?

(a) If a transfer of ownership of the record title interest only
changes the percentage ownership of the record title, no new parties or
new aliquots are involved in the transaction, and no change of
designated operator is made, you will not need to submit a new
designation of operator form.
(b) In all cases other than that in paragraph (a) of this section,
you must submit new designation of operator forms in accordance with
Sec. 550.143 of this chapter. In the event that you are transferring
multiple record title interests, you must comply with this requirement
for each interest that does not fall within paragraph (a) of this
section.

Subpart H_Transferring All or Part of the Operating Rights in a Lease

Sec. 556.800 As an operating rights owner, may I assign all or part
of my operating rights interest?

An operating rights owner may assign all or part of its operating
rights interests, subject to BOEM approval. Each instrument that
transfers an interest must describe, by officially designated aliquot
parts and depth levels, the interest proposed to be transferred.

Sec. 556.801 How do I seek approval of an assignment of my operating rights?

(a) The Regional Director will provide the form to document the
assignment of an operating rights interest. You must request approval of
each assignment of operating rights and submit to BOEM two originals of
each instrument that transfers ownership of operating rights within 90
days after the last party executes the transfer instrument. You must pay
the service fee listed in Sec. 556.106 with your request and your
submission must include evidence of payment via pay.gov.
(b) A new operating rights owner must file a designation of
operator, in accordance with Sec. 550.143, along with the request for
the approval of the assignment.
(c) If an operating rights owner assigns an undivided ownership
interest in its operating rights, that assignment creates a joint
ownership in the operating rights.
(d) Before BOEM approves a sublease or re-assignment of operating
rights, BOEM may consult with and consider the views of the Attorney
General.

[[Page 477]]

Sec. 556.802 When would BOEM disapprove the assignment of all or part
of my operating rights interest?

BOEM may disapprove an assignment of all or part of your operating
rights interest:
(a) When the transferor or transferee has outstanding or unsatisfied
obligations under this chapter or 30 CFR chapter II or XII;
(b) When a transferor attempts a transfer that is not acceptable as
to form or content (e.g., not on standard form, containing incorrect
legal description, not executed in accordance with corporate governance,
transferee does not meet the requirements of Sec. 556.401, etc.); or
(c) When the transfer does not conform to these regulations, or any
other applicable laws or regulations (e.g., departmental debarment
rules).

Sec. 556.803 What if I want to assign operating rights interests
in more than one lease at the same time, but to different parties?

You may not assign operating rights interests in more than one lease
to different parties using the same instrument. If you want to transfer
operating rights interests in more than one lease at the same time, you
must submit two originally executed forms for each transfer. Each
request for a transfer of operating rights interest must be accompanied
by a cover letter executed by one of the parties to the transfer (or an
authorized agent thereof) and evidence of payment via pay.gov.

Sec. 556.804 What if I want to assign my operating rights interest
in a lease to multiple parties?

You may assign your operating rights interest in one lease to
multiple parties using the same instrument. That instrument must be
submitted in duplicate originals, accompanied by a cover letter executed
by one of the parties to the transfer (or an authorized agent thereof).
In such a multiple transfer of interests using a single instrument, a
separate fee applies to each individual transfer of interest and
evidence of payment via pay.gov must accompany the instrument.

Sec. 556.805 What is the effect of an operating rights owner's assignment
of operating rights on the assignor's liability?

An operating rights owner (who does not hold record title) who
assigns the operating rights remains liable for all obligations of the
lease that accrued during the period in which the assignor owned the
operating rights, up to the effective date of the assignment, including
decommissioning obligations that accrued during that period. BOEM's
approval of the assignment does not alter that liability. Even after
assignment, BOEM or BSEE may require the assignor to bring the lease
into compliance if the assignee or any subsequent assignee fails to
perform any obligation under the lease, to the extent the obligation
accrued before approval of the assignment.

Sec. 556.806 What is the effective date of an assignment of operating rights?

An assignment is effective at 12:01 a.m. on the first day of the
month following the date on which BOEM approves your request, unless you
request an earlier effective date and BOEM approves that earlier date.
Such an earlier effective date, if prior to the date of BOEM's approval,
does not relieve you of obligations accrued between that earlier
effective date and the date of approval.

Sec. 556.807 What is the effect of an assignment of operating rights
on an assignee's liability?

As assignee, you and any subsequent assignees are liable for all
obligations that accrue after the effective date of your assignment. As
assignee, you must comply with all the terms and conditions of the lease
and regulations issued under OCSLA. In addition, you must remedy all
existing environmental and operational problems on the lease, properly
abandon all wells, and reclaim the site, as required under 30 CFR part
250.

Sec. 556.808 As an operating rights owner, are there any interests
I may assign without BOEM approval?

(a) You may create, transfer, or assign economic interests without
BOEM approval. However, for record purposes,

[[Page 478]]

you must send BOEM a copy of each instrument creating or transferring
such interests within 90 days after the last party executes the transfer
instrument. For each lease affected, you must pay the service fee listed
in Sec. 556.106 with your documents submitted for record purposes, and
your submission must include evidence of payment via pay.gov.
(b) For record keeping purposes, you may also submit other legal
documents to BOEM for transactions that do not require BOEM approval. If
you submit such documents for record purposes that are not required by
these regulations, for each lease affected, you must pay the service fee
listed in Sec. 556.106 with your document submissions, and your
submission must include evidence of payment via pay.gov.

Sec. 556.809 [Reserved]

Sec. 556.810 What must I do with respect to the designation of operator
on a lease when a transfer of operating rights ownership is submitted?

(a) If a transfer of ownership of operating rights only changes the
percentage ownership; no new parties, new aliquots, or new depths are
involved in the transaction; and no change of designated operator is
made, you will not need to submit a new designation of operator form.
(b) In all cases other than that in paragraph (a) of this section,
you must submit new designation of operator forms, in accordance with
Sec. 550.143 of this chapter. In the event that you are transferring
multiple operating rights interests, you must comply with this
requirement for each interest that does not fall within paragraph (a) of
this section.

Subpart I_Bonding or Other Financial Assurance

Sec. 556.900 Bond requirements for an oil and gas or sulfur lease.

This section establishes bond requirements for the lessee of an OCS
oil and gas or sulfur lease.
(a) Before BOEM will issue a new lease or approve the assignment of
an existing lease to you as lessee, you or another record title owner
for the lease must:
(1) Maintain with the Regional Director a $50,000 lease bond that
guarantees compliance with all the terms and conditions of the lease; or
(2) Maintain a $300,000 area-wide bond that guarantees compliance
with all the terms and conditions of all your oil and gas and sulfur
leases in the area where the lease is located; or
(3) Maintain a lease or area-wide bond in the amount required in
Sec. 556.901(a) or (b).
(b) For the purpose of this section, there are three areas. The
three areas are:
(1) The Gulf of Mexico and the area offshore the Atlantic Coast;
(2) The area offshore the Pacific Coast States of California,
Oregon, Washington, and Hawaii; and
(3) The area offshore the Coast of Alaska.
(c) The requirement to maintain a lease bond (or substitute security
instrument) under paragraph (a)(1) of this section and Sec. 556.901(a)
and (b) may be satisfied if your operator or an operating rights owner
provides a lease bond in the required amount that guarantees compliance
with all the terms and conditions of the lease. Your operator or an
operating rights owner may use an areawide bond under this paragraph to
satisfy your bond obligation.
(d) If a surety makes payment to the United States under a bond or
alternative form of security maintained under this section, the surety's
remaining liability under the bond or alternative form of security is
reduced by the amount of that payment. See paragraph (e) of this section
for the requirement to replace the reduced bond coverage.
(e) If the value of your surety bond or alternative security is
reduced because of a default or for any other reason, you must provide
additional bond coverage sufficient to meet the security required under
this subpart within 6 months, or such shorter period of time as the
Regional Director may direct.
(f) You may pledge United States Department of the Treasury
(Treasury)

[[Page 479]]

securities instead of a bond. The Treasury securities you pledge must be
negotiable for an amount of cash equal to the value of the bond they
replace.
(1) If you pledge Treasury securities under this paragraph (f), you
must monitor their value. If their market value falls below the level of
bond coverage required under this subpart, you must pledge additional
Treasury securities to raise the value of the securities pledged to the
required amount.
(2) If you pledge Treasury securities, you must include authority
for the Regional Director to sell them and use the proceeds in the event
that the Regional Director determines that you fail to satisfy any lease
obligation.
(g) You may pledge alternative types of security instruments instead
of providing a bond if the Regional Director determines that the
alternative security protects the interests of the United States to the
same extent as the required bond.
(1) If you pledge an alternative type of security under this
paragraph, you must monitor the security's value. If its market value
falls below the level of bond coverage required under this subpart, you
must pledge additional securities to raise the value of the securities
pledged to the required amount.
(2) If you pledge an alternative type of security, you must include
authority for the Regional Director to sell the security and use the
proceeds when the Regional Director determines that you failed to
satisfy any lease obligation.
(h) If you fail to replace a deficient bond or to provide additional
bond coverage upon demand, the Regional Director may:
(1) Assess penalties under part 550, subpart N of this chapter;
(2) Suspend production and other operations on your leases in
accordance with 30 CFR 250.173; and
(3) Initiate action to cancel your lease.

Sec. 556.901 Additional bonds.

(a) This paragraph explains what bonds you must provide before lease
exploration activities commence.
(1)(i) You must furnish the Regional Director a $200,000 bond that
guarantees compliance with all the terms and conditions of the lease by
the earliest of:
(A) The date you submit a proposed exploration plan (EP) for
approval; or
(B) The date you submit a request for approval of the assignment of
a lease on which an EP has been approved.
(ii) The Regional Director may authorize you to submit the $200,000
lease exploration bond after you submit an EP, but before approval of
drilling activities under the EP.
(iii) You may satisfy the bond requirement of this paragraph (a) by
providing a new bond or by increasing the amount of your existing bond.
(2) A $200,000 lease exploration bond pursuant to paragraph (a)(1)
of this section need not be submitted and maintained if the lessee
either:
(i) Furnishes and maintains an areawide bond in the sum of $1
million issued by a qualified surety and conditioned on compliance with
all the terms and conditions of oil and gas and sulfur leases held by
the lessee on the OCS for the area in which the lease is situated; or
(ii) Furnishes and maintains a bond pursuant to paragraph (b)(2) of
this section.
(b) This paragraph explains what bonds you (the lessee) must provide
before lease development and production activities commence.
(1)(i) You must furnish the Regional Director a $500,000 bond that
guarantees compliance with all the terms and conditions of the lease by
the earliest of:
(A) The date you submit a proposed development and production plan
(DPP) or development operations coordination document (DOCD) for
approval; or
(B) The date you submit a request for approval of the assignment of
a lease on which a DPP or DOCD has been approved.
(ii) The Regional Director may authorize you to submit the $500,000
lease development bond after you submit a DPP or DOCD, but before he/she
approves the installation of a platform or the commencement of drilling
activities under the DPP or DOCD.

[[Page 480]]

(iii) You may satisfy the bond requirement of this paragraph by
providing a new bond or by increasing the amount of your existing bond.
(2) You need not submit and maintain a $500,000 lease development
bond pursuant to paragraph (b)(1) of this section if you furnish and
maintain an areawide bond in the sum of $3 million issued by a qualified
surety and conditioned on compliance with all the terms and conditions
of oil and gas and sulfur leases you hold on the OCS for the area in
which the lease is located.
(c) If you can demonstrate to the satisfaction of the authorized
officer that you can satisfy your decommissioning obligations for less
than the amount of lease bond coverage required under paragraph (b)(1)
of this section, the authorized officer may accept a lease surety bond
in an amount less than the prescribed amount, but not less than the
amount of the cost for decommissioning.
(d) The Regional Director may determine that additional security
(i.e., security above the amounts prescribed in Sec. 556.900(a) and
paragraphs (a) and (b) of this section) is necessary to ensure
compliance with the obligations under your lease, the regulations in
this chapter, and the regulations in 30 CFR chapters II and XII.
(1) The Regional Director's determination will be based on his/her
evaluation of your ability to carry out present and future financial
obligations demonstrated by:
(i) Financial capacity substantially in excess of existing and
anticipated lease and other obligations, as evidenced by audited
financial statements (including auditor's certificate, balance sheet,
and profit and loss sheet);
(ii) Projected financial strength significantly in excess of
existing and future lease obligations based on the estimated value of
your existing OCS lease production and proven reserves for future
production;
(iii) Business stability based on five years of continuous operation
and production of oil and gas or sulfur in the OCS or in the onshore oil
and gas industry;
(iv) Reliability in meeting obligations based on:
(A) Credit rating; or
(B) Trade references, including names and addresses of other
lessees, drilling contractors, and suppliers with whom you have dealt;
and
(v) Record of compliance with laws, regulations, and lease terms.
(2) You may satisfy the Regional Director's demand for additional
security by increasing the amount of your existing bond or by providing
additional bond or bonds.
(e) The Regional Director will determine the amount of additional
bond required to guarantee compliance. The Regional Director will
consider potential underpayment of royalty and cumulative
decommissioning obligations.
(f) If your cumulative potential obligations and liabilities either
increase or decrease, the Regional Director may adjust the amount of
additional bond required.
(1) If the Regional Director proposes an adjustment, the Regional
Director will:
(i) Notify you and the surety of any proposed adjustment to the
amount of bond required; and
(ii) Give you an opportunity to submit written or oral comment on
the adjustment.
(2) If you request a reduction of the amount of additional bond
required, you must submit evidence to the Regional Director
demonstrating that the projected amount of royalties due the Government
and the estimated costs of decommissioning are less than the required
bond amount. If the Regional Director finds that the evidence you submit
is convincing, the Regional Director may reduce the amount of additional
bond required.

Sec. 556.902 General requirements for bonds.

(a) Any bond or other security that you, as lessee, operating rights
owner or operator, provide under this part must:
(1) Be payable upon demand to the Regional Director;
(2) Guarantee compliance with all of your obligations under the
lease, regulations in this chapter, and regulations under 30 CFR
chapters II and XII; and
(3) Guarantee compliance with the obligations of all lessees,
operating

[[Page 481]]

rights owners and operators on the lease.
(b) All bonds and pledges you furnish under this part must be on a
form or in a form approved by the Director. Surety bonds must be issued
by a surety that the Treasury certifies as an acceptable surety on
Federal bonds and that is listed in the current Treasury Circular No.
570. You may obtain a copy of the current Treasury Circular No. 570 from
the Surety Bond Branch, Financial Management Service, Department of the
Treasury, East-West Highway, Hyattsville, MD 20782.
(c) You and a qualified surety must execute your bond. When either
party is a corporation, an authorized official for the party must sign
the bond and attest to it by an imprint of the corporate seal.
(d) Bonds must be non-cancellable, except as provided in Sec.
556.906 of this part. Bonds must continue in full force and effect even
though an event occurs that could diminish, terminate, or cancel a
surety obligation under State surety law.
(e) Lease bonds must be:
(1) A surety bond;
(2) Treasury securities as provided in Sec. 556.900(f);
(3) Another form of security approved by the Regional Director; or
(4) A combination of these security methods.
(f) You may submit a bond to the Regional Director executed on a
form approved under paragraph (b) of this section that you have
reproduced or generated by use of a computer. If you do, and if the
document omits terms or conditions contained on the form approved by the
Director, the bond you submit will be deemed to contain the omitted
terms and conditions.

Sec. 556.903 Lapse of bond.

(a) If your surety becomes bankrupt, insolvent, or has its charter
or license suspended or revoked, any bond coverage from that surety
terminates immediately. In that event, you must promptly provide a new
bond in the amount required under Sec. Sec. 556.900 and 556.901 to the
Regional Director and advise the Regional Director of the lapse in your
previous bond.
(b) You must notify the Regional Director of any action filed
alleging that you, your surety, or your guarantor are insolvent or
bankrupt. You must notify the Regional Director within 72 hours of
learning of such an action. All bonds must require the surety to provide
this information to you and directly to BOEM.

Sec. 556.904 Lease-specific abandonment accounts.

(a) The Regional Director may authorize you to establish a lease-
specific abandonment account in a federally insured institution in lieu
of the bond required under Sec. 556.901(d). The account must provide
that, except as provided in paragraph (a)(3) of this section, funds may
not be withdrawn without the written approval of the Regional Director.
(1) Funds in a lease-specific abandonment account must be payable
upon demand to BOEM and pledged to meet your decommissioning
obligations.
(2) You must fully fund the lease-specific abandonment account to
cover all decommissioning costs as estimated by BOEM within the
timeframe the Regional Director prescribes.
(3) You must provide binding instructions under which the
institution managing the account is to purchase Treasury securities
pledged to BOEM under paragraph (d) of this section.
(b) Any interest paid on funds in a lease-specific abandonment
account will be treated as other funds in the account unless the
Regional Director authorizes in writing the payment of interest to the
party who deposits the funds.
(c) The Regional Director may allow you to pledge Treasury
securities that are made payable upon demand to the Regional Director to
satisfy your obligation to make payments into a lease-specific
abandonment account.
(d) Before the amount of funds in a lease-specific abandonment
account equals the maximum insurable amount as determined by the Federal
Deposit Insurance Corporation or the Federal Savings and Loan Insurance
Corporation, the institution managing the account must use the funds in
the account to purchase Treasury securities pledged to BOEM under
paragraph (c)

[[Page 482]]

of this section. The institution managing the lease specific-abandonment
account will join with the Regional Director to establish a Federal
Reserve Circular 154 account to hold these Treasury securities, unless
the Regional Director authorizes the managing institution to retain the
pledged Treasury securities in a separate trust account. You may obtain
a copy of the current Treasury Circular No. 154 from the Surety Bond
Branch, Financial Management Service, Department of the Treasury, East-
West Highway, Hyattsville, MD 20782.
(e) The Regional Director may require you to create an overriding
royalty or production payment obligation for the benefit of a lease-
specific account pledged for the decommissioning of a lease. The
required obligation may be associated with oil and gas or sulfur
production from a lease other than the lease bonded through the lease-
specific abandonment account.

Sec. 556.905 Using a third-party guarantee instead of a bond.

(a) When the Regional Director may accept a third-party guarantee.
The Regional Director may accept a third-party guarantee instead of an
additional bond under Sec. 556.901(d) if:
(1) The guarantee meets the criteria in paragraph (c) of this
section;
(2) The guarantee includes the terms specified in paragraph (d) of
this section;
(3) The guarantor's total outstanding and proposed guarantees do not
exceed 25 percent of its unencumbered net worth in the United States;
and
(4) The guarantor submits an indemnity agreement meeting the
criteria in paragraph (e) of this section.
(b) What to do if your guarantor becomes unqualified. If, during the
life of your third-party guarantee, your guarantor no longer meets the
criteria of paragraphs (a)(3) and (c)(3) of this section, you must:
(1) Notify the Regional Director immediately; and
(2) Cease production until you comply with the bond coverage
requirements of this subpart.
(c) Criteria for acceptable guarantees. If you propose to furnish a
third party's guarantee, that guarantee must ensure compliance with all
lessees' lease obligations, the obligations of all operating rights
owners, and the obligations of all operators on the lease. The Regional
Director will base acceptance of your third-party guarantee on the
following criteria:
(1) The period of time that your third-party guarantor (guarantor)
has been in continuous operation as a business entity where:
(i) Continuous operation is the time that your guarantor conducts
business immediately before you post the guarantee; and
(ii) Continuous operation excludes periods of interruption in
operations that are beyond your guarantor's control and that do not
affect your guarantor's likelihood of remaining in business during
exploration, development, production, and decommissioning.
(2) Financial information available in the public record or
submitted by your guarantor, on your guarantor's own initiative, in
sufficient detail to show to the Regional Director's satisfaction that
your guarantor is qualified based on:
(i) Your guarantor's current rating for its most recent bond
issuance by either Moody's Investor Service or Standard and Poor's
Corporation;
(ii) Your guarantor's net worth, taking into account liabilities
under its guarantee of compliance with all the terms and conditions of
your lease, the regulations in this chapter and 30 CFR chapters II and
XII, and your guarantor's other guarantees;
(iii) Your guarantor's ratio of current assets to current
liabilities, taking into account liabilities under its guarantee of
compliance with all the terms and conditions of your lease, the
regulations in this chapter and 30 CFR chapters II and XII, and your
guarantor's other guarantees; and
(iv) Your guarantor's unencumbered fixed assets in the United
States.
(3) When the information required by paragraph (c) of this section
is not publicly available, your guarantor may submit the information in
the following table. Your guarantor must update the information annually
within 90 days of the end of the fiscal year or by the date prescribed
by the Regional Director.

[[Page 483]]

------------------------------------------------------------------------
The guarantor should submit That
------------------------------------------------------------------------
(i) Financial statements for the most Include a report by an
recently completed fiscal year, independent certified public
accountant containing the
accountant's audit opinion or
review opinion of the
statements. The report must be
prepared in conformance with
generally accepted accounting
principles and contain no
adverse opinion.
(ii) Financial statements for Your guarantor's financial
completed quarters in the current officer certifies to be correct.
fiscal year, and
(iii) Additional information as Your guarantor's financial
requested by the Regional Director. officer certifies to be correct.
------------------------------------------------------------------------

(d) Provisions required in all third-party guarantees. Your third-
party guarantee must contain each of the following provisions.
(1) If you, your operator, or an operating rights owner fails to
comply with any lease term or regulation, your guarantor must either:
(i) Take corrective action; or,
(ii) Be liable under the indemnity agreement to provide, within 7
calendar days, sufficient funds for the Regional Director to complete
corrective action.
(2) If your guarantor complies with paragraph (d)(1) of this
section, this compliance will not reduce its liability.
(3) If your guarantor wishes to terminate the period of liability
under its guarantee, it must:
(i) Notify you and the Regional Director at least 90 days before the
proposed termination date;
(ii) Obtain the Regional Director's approval for the termination of
the period of liability for all or a specified portion of your
guarantor's guarantee; and
(iii) Remain liable for all work and workmanship performed during
the period that your guarantor's guarantee is in effect.
(4) You must provide a suitable replacement security instrument
before the termination of the period of liability under your third-party
guarantee.
(e) Required criteria for indemnity agreements. If the Regional
Director approves your third-party guarantee, the guarantor must submit
an indemnity agreement.
(1) The indemnity agreement must be executed by your guarantor and
all persons and parties bound by the agreement.
(2) The indemnity agreement must bind each person and party
executing the agreement jointly and severally.
(3) When a person or party bound by the indemnity agreement is a
corporate entity, two corporate officers who are authorized to bind the
corporation must sign the indemnity agreement.
(4) Your guarantor and the other corporate entities bound by the
indemnity agreement must provide the Regional Director copies of:
(i) The authorization of the signatory corporate officials to bind
their respective corporations;
(ii) An affidavit certifying that the agreement is valid under all
applicable laws; and
(iii) Each corporation's corporate authorization to execute the
indemnity agreement.
(5) If your third-party guarantor or another party bound by the
indemnity agreement is a partnership, joint venture, or syndicate, the
indemnity agreement must:
(i) Bind each partner or party who has a beneficial interest in your
guarantor; and
(ii) Provide that, upon demand by the Regional Director under your
third-party guarantee, each partner is jointly and severally liable for
compliance with all terms and conditions of your lease.
(6) When forfeiture is called for under Sec. 556.907, the indemnity
agreement must provide that your guarantor will either:
(i) Bring your lease into compliance; or
(ii) Provide, within 7 calendar days, sufficient funds to permit the
Regional Director to complete corrective action.
(7) The indemnity agreement must contain a confession of judgment.
It must provide that, if the Regional Director determines that you, your
operator, or an operating rights owner is in default of the lease, the
guarantor:

[[Page 484]]

(i) Will not challenge the determination; and
(ii) Will remedy the default.
(8) Each indemnity agreement is deemed to contain all terms and
conditions contained in this paragraph (e), even if the guarantor has
omitted them.

Sec. 556.906 Termination of the period of liability
and cancellation of a bond.

This section defines the terms and conditions under which BOEM will
terminate the period of liability of a bond or cancel a bond.
Terminating the period of liability of a bond ends the period during
which obligations continue to accrue, but does not relieve the surety of
the responsibility for obligations that accrued during the period of
liability. Canceling a bond relieves the surety of all liability. The
liabilities that accrue during a period of liability include obligations
that started to accrue prior to the beginning of the period of liability
and had not been met, and obligations that begin accruing during the
period of liability.
(a) When you or the surety under your bond requests termination:
(1) The Regional Director will terminate the period of liability
under your bond within 90 days after BOEM receives the request; and
(2) If you intend to continue operations, or have not met all
decommissioning obligations, you must provide a replacement bond of an
equivalent amount.
(b) If you provide a replacement bond, the Regional Director will
cancel your previous bond and the surety that provided your previous
bond will not retain any liability, provided that:
(1) The new bond is equal to or greater than the bond that was
terminated, or you provide an alternative form of security, and the
Regional Director determines that the alternative form of security
provides a level of security equal to or greater than that provided for
by the bond that was terminated;
(2) For a base bond submitted under Sec. 556.900(a) or under Sec.
556.901(a) or (b), the surety issuing the new bond agrees to assume all
outstanding liabilities that accrued during the period of liability that
was terminated; and
(3) For additional bonds submitted under Sec. 556.901(d), the
surety issuing the new additional bond agrees to assume that portion of
the outstanding liabilities that accrued during the period of liability
that was terminated and that the Regional Director determines may exceed
the coverage of the base bond, and of which the Regional Director
notifies the provider of the bond.
(c) This paragraph applies if the period of liability is terminated
for a bond, but the bond is not replaced by a bond of an equivalent
amount. The surety that provided your terminated bond will continue to
be responsible for accrued obligations:
(1) Until the obligations are satisfied; and
(2) For additional periods of time in accordance with paragraph (d)
of this section.
(d) When your lease expires or is terminated, the surety that issued
a bond will continue to be responsible, and the Regional Director will
retain other forms of security as shown in the following table:

------------------------------------------------------------------------
The period of
For the following type of bond liability will Your bond will be
end cancelled
------------------------------------------------------------------------
(1) Base bonds submitted under When the Regional Seven years after the
Sec. 556.900(a), Sec. Director termination of the
556.901(a), or (b). determines that lease, 6 years after
you have met all completion of all
of your bonded obligations,
obligations or at the conclusion
under the lease, of any appeals or
litigation related
to your bonded
obligation,
whichever is the
latest. The Regional
Director will reduce
the amount of your
bond or return a
portion of your
security if the
Regional Director
determines that you
need less than the
full amount of the
base bond to meet
any possible future
problems.
(2) Additional bonds submitted When the Regional When you meet your
under Sec. 556.901(d). Director bonded obligations,
determines that unless the Regional
you have met all Director: (i)
your obligations Determines that the
covered by the future potential
additional bond, liability resulting
from any undetected
problem is greater
than the amount of
the base bond; and
(ii) Notifies the
provider of the bond
that the Regional
Director will wait 7
years before
cancelling all or a
part of the bond (or
longer period as
necessary to
complete any appeals
or judicial
litigation related
to your bonding
obligation).
------------------------------------------------------------------------

[[Page 485]]

(e) For all bonds, the Regional Director may reinstate your bond as
if no cancellation or release had occurred if:
(1) A person makes a payment under the lease and the payment is
rescinded or must be repaid by the recipient because the person making
the payment is insolvent, bankrupt, subject to reorganization, or placed
in receivership; or
(2) The responsible party represents to BOEM that it has discharged
its obligations under the lease, and the representation was materially
false when the bond was canceled or released.

Sec. 556.907 Forfeiture of bonds and/or other securities.

This section explains how a bond or other security may be forfeited.
(a) The Regional Director will call for forfeiture of all or part of
the bond, other form of security, or guarantee you provide under this
part if:
(1) You (the party who provided the bond) refuse, or the Regional
Director determines that you are unable to comply with any term or
condition of your lease; or
(2) You default on one of the conditions under which the Regional
Director accepts your bond, third-party guarantee, and/or other form of
security.
(b) The Regional Director may pursue forfeiture of your bond without
first making demands for performance against any lessee, operating
rights owner, or other person authorized to perform lease obligations.
(c) The Regional Director will:
(1) Notify you, the surety on your bond or other form of security,
and any third-party guarantor of a determination to call for forfeiture
of the bond, security, or guarantee under this section.
(i) This notice will be in writing, and will provide the reason for
the forfeiture and the amount to be forfeited.
(ii) The Regional Director must base the amount he/she determines is
forfeited upon his/her estimate of the total cost of corrective action
to bring your lease into compliance.
(2) Advise you, your third-party guarantor, and any surety that you,
your guarantor, and any surety may avoid forfeiture if, within five
working days:
(i) You agree to, and demonstrate that you will bring your lease
into compliance within the timeframe that the Regional Director
prescribes;
(ii) Your third-party guarantor agrees to and demonstrates that it
will complete the corrective action to bring your lease into compliance
within the timeframe that the Regional Director prescribes; or
(iii) Your surety agrees to and demonstrates that it will bring your
lease into compliance within the timeframe that the Regional Director
prescribes, even if the cost of compliance exceeds the face amount of
the bond or other surety instrument.
(d) If the Regional Director finds you are in default, he/she may
cause the forfeiture of any bonds and other security deposited as your
guarantee of compliance with the terms and conditions of your lease and
the regulations in this chapter and 30 CFR chapters II and XII.
(e) If the Regional Director determines that your bond and/or other
security is forfeited, the Regional Director will:
(1) Collect the forfeited amount; and
(2) Use the funds collected to bring your leases into compliance and
to correct any default.
(f) If the amount the Regional Director collects under your bond and
other security is insufficient to pay the full cost of corrective
actions he/she may:
(1) Take or direct action to obtain full compliance with your lease
and the regulations in this chapter; and
(2) Recover from you, any co-lessee, operating rights owner, and/or
any third-party guarantor responsible under this subpart all costs in
excess of the amount he/she collects under your forfeited bond and other
security.
(g) The amount that the Regional Director collects under your
forfeited bond and other security may exceed the costs of taking the
corrective actions required to obtain full compliance with the terms and
conditions of your lease and the regulations in this chapter and 30 CFR
chapters II and XII. In this case, the Regional Director will return the
excess funds to the party from whom they were collected.

[[Page 486]]

Subpart J_Bonus or Royalty Credits for Exchange of Certain Leases

Sec. 556.1000 Leases formerly eligible for a bonus or royalty credit.

Bonus or royalty credits were available to lessees with leases:
(a) In effect on December 20, 2006, and located in:
(1) The Eastern Planning Area and within 125 miles of the coastline
of the State of Florida; or,
(2) The Central Planning Area and within the Desoto Canyon OPD, the
Destin Dome OPD, or the Pensacola OPD and within 100 miles of the
coastline of the State of Florida.
(b) The deadline for applying for such a bonus or royalty credit was
October 14, 2010; therefore, lessees may no longer apply for such
credits.

Subpart K_Ending a Lease

Sec. 556.1100 How does a lease expire?

(a) Your oil and gas lease will automatically expire at the end of
its primary term unless you have taken action, as set forth in Sec.
556.601, to maintain the lease beyond the primary term.
(b) Your sulfur lease will automatically expire at the end of its
primary term unless you have taken action, as set forth in Sec.
556.603, to maintain the lease beyond the primary term.

Sec. 556.1101 May I relinquish my lease or an aliquot part thereof?

(a) A record title owner may relinquish a lease or an aliquot part
of a lease if all record title owners of a lease or any aliquot part(s)
of the lease file three original copies of a request to relinquish with
BOEM on Form BOEM-0152, entitled, ``Relinquishment of Federal Oil and
Gas Lease.'' No filing fee is required.
(b) A relinquishment will be subject to the continued obligation of
the record title owner and the surety to make all payments due,
including any accrued rentals, royalties and deferred bonuses, and to
abandon all wells and condition or remove all platforms and other
facilities on the land to be relinquished to the satisfaction of the
Director.
(c) The effective date of the relinquishment is the date on which
the relinquishment is filed with the proper BOEM regional office.

Sec. 556.1102 Under what circumstances will BOEM cancel my lease?

(a) BOEM may cancel your non-producing lease if you fail to comply
with any provision of OCSLA, the lease, or applicable regulations if the
failure continues for 30 days after mailing of notice to your post
office address of record by registered mail and you have not requested
and been granted any additional time within which to correct the
failure. Such cancellation is subject to judicial review under section
23 of OCSLA (43 U.S.C. 1349).
(b) Your producing lease may be cancelled if you fail to comply with
any provision of OCSLA, the lease, or applicable regulations. The
Secretary will cancel a producing lease after the judicial proceedings
required under section 5(d) of OCSLA (43 U.S.C. 1334(d)).
(c) BOEM may cancel your lease if it determines that the lease was
obtained by fraud or misrepresentation. You will have notice and an
opportunity to be heard before BOEM cancels your lease.
(d) BOEM may cancel your lease at any time if it determines, after a
hearing, that continued activity will probably cause serious harm or
damage to life (including fish and other aquatic life), property, any
mineral, national security or defense, or the marine, coastal, or human
environment; that the threat of harm or damage will not disappear or
decrease to an acceptable level within a reasonable period of time; and
the advantages of cancellation outweigh the advantages of continuing the
lease.
(e) BOEM may cancel your lease at any time after operations under
the lease have been suspended or temporarily prohibited by the
Department continuously for a period of five years pursuant to paragraph
(d) of this section, absent your request for a shorter period.
(f) If, upon demand, you fail to provide a bond, or alternative type
of security instrument acceptable to BOEM,

[[Page 487]]

the Regional Director may assess penalties or cancel your lease in
accordance with part 550, subpart N of this chapter;
(g) Title 30, part 550, subpart A of the CFR provides the procedures
for lease cancellation and compensation, if applicable.

Subpart L_Leases Maintained Under Section 6 of OCSLA

Sec. 556.1200 Effect of regulations on lease.

(a) All regulations in this part, insofar as they are applicable,
will supersede the provisions of any lease that is maintained under
section 6(a) of the Act. However, the provisions of a lease relating to
area, minerals, rentals, royalties (subject to sections 6(a)(8) and (9)
of the Act), and term (subject to section 6(a)(10) of the Act and, as to
sulfur, subject to section 6(b)(2) of the Act) will continue in effect,
and, in the event of any conflict or inconsistency, will take precedence
over these regulations.
(b) A lease maintained under section 6(a) of the Act is also subject
to all operating and conservation regulations applicable to the OCS. In
addition, the regulations relating to geophysical and geological
exploratory operations and to pipeline ROW(s) are applicable, to the
extent that those regulations are not contrary to or inconsistent with
the lease provisions relating to area, minerals, rentals, royalties and
term. The lessee must comply with any provision of the lease as
validated, the subject matter of which is not covered in the regulations
in this part.

Sec. 556.1201 Section 6(a) leases and leases other than those
for oil, gas, or sulfur.

The existence of an oil and gas lease maintained under section 6(a)
of the Act precludes only the issuance in the same area of an oil and
gas lease under OCSLA, but does not preclude the issuance of other types
of leases under OCSLA. However, no other lease may authorize or permit
the lessee thereunder unreasonably to interfere with or endanger
operations under the existing lease. The United States will not grant
any sulfur leases on any area that is included in a lease covering
sulfur under section 6(b) of the Act.

Subpart M_Environmental Studies

Sec. 556.1300 Environmental studies.

(a) The Director will conduct a study or studies of any area or
region included in any oil and gas lease sale or other lease in order to
establish information needed for assessment and management of impacts on
the human, marine and coastal environments which may be affected by OCS
oil and gas or other mineral activities in such area or region. The
purposes of such studies will include, to the extent practicable,
analyses of the impacts of pollutants introduced into the environments
and impacts of offshore activities on the seabed and affected coastal
areas.
(b) Studies will be planned and carried out in cooperation with the
affected States and interested parties and, to the extent possible, will
not duplicate studies done under other laws. Where appropriate, the
Director will, to the maximum extent practicable, coordinate with the
National Oceanic and Atmospheric Administration (NOAA) in executing its
environmental studies responsibilities. The Director may also make
agreements for the coordination with, or the use of the services or
resources of, any other Federal, State or local government agency in the
conduct of such studies.
(c) Any study of an area or region required by paragraph (a) of this
section for a lease sale will be commenced not later than six months
prior to holding a lease sale for that area. The Director may use
information collected in any prior study. The Director may initiate
studies for an area or region not identified in the leasing program.
(d) After the leasing and developing of any area or region, the
Director will conduct such studies as are deemed necessary to establish
additional information and will monitor the human, marine and coastal
environments of such area or region in a manner designed to provide
information, which can be compared with the results of studies conducted
prior to OCS oil and gas development. This will be done to identify any
significant changes in the

[[Page 488]]

quality and productivity of such environments, to establish trends in
the area studies, and to design experiments identifying the causes of
such changes. Findings from such studies will be used to recommend
modifications in practices that are employed to mitigate the effects of
OCS activities and to enhance the data/information base for predicting
impacts which might result from a single lease sale or cumulative OCS
activities.
(e) Information available or collected by the studies program will,
to the extent practicable, be provided in a form and in a timeframe that
can be used in the decision-making process associated with a specific
leasing action or with longer term OCS minerals management
responsibilities.

PART 560_OUTER CONTINENTAL SHELF OIL AND GAS LEASING--Table of Contents

Subpart A_General Provisions

560.100 Authority
560.100 What is the purpose of this part?
560.102 What definitions apply to this part?
560.103 What is BOEM's authority to collect information?

Subpart B_Bidding Systems

General Provisions

560.200 What is the purpose of this subpart?
560.201 What definitions apply to this subpart?
560.202 What bidding systems may BOEM use?
560.203 What conditions apply to the bidding systems that BOEM uses?

Eligible Leases

560.210 How do royalty suspension volumes apply to eligible leases?
560.211 When does an eligible lease qualify for a royalty suspension
volume?
560.212 How does BOEM assign and monitor royalty suspension volumes for
eligible leases?
560.213 How long will a royalty suspension volume for an eligible lease
be effective?
550.214 How do I measure natural gas production on my eligible lease?

Royalty Suspensions (RS) Leases

560.220 How does royalty suspension apply to leases issued in a sale
held after November 2000?
560.221 When does a lease issued in a sale held after November 2000 get
a royalty suspension?
560.222 How long will a royalty suspension volume be effective for a
lease issued in a sale held after November 2000?
560.223 How do I measure natural gas production for a lease issued in a
sale held after November 2000?
560.224 How will royalty suspension apply if BOEM assigns a lease issued
in a sale held after November 2000 to a field that has a pre-
Act lease?

Bidding System Selection Criteria

560.230 What criteria does BOEM use for selecting bidding systems and
bidding system components?

Subpart C_Operating Allowances

560.300 Operating allowances.

Subpart D [Reserved]

Subpart E_Electronic Filings

560.500 Electronic document and data transmissions.
560.501 How long will the confidentiality of electronic document and
data transmissions be maintained?
560.502 Are electronically filed document transmissions legally binding?

Source: 76 FR 64623, Oct. 18, 2011, unless otherwise noted.

Subpart A_General Provisions

Sec. 560.100 Authority.

(a) The Outer Continental Shelf Lands Act (OCSLA) (43 U.S.C. 1334)
(``Outer Continental Shelf Lands Act Amendments of 1978'').
(b) The Federal Oil and Gas Royalty Management Act, as amended
(FOGRMA) (30 U.S.C. 1711), including the Federal Oil and Gas Royalty
Simplification and Fairness Act of 1996, (30 U.S.C. 1701 note).
(c) The Independent Offices Appropriations Act of 1952 (31 U.S.C.
9701).
(d) Public Law 89-554, 1966 (5 U.S.C. 301).

[81 FR 18175, Mar. 30, 2016]

[[Page 489]]

Sec. 560.101 What is the purpose of this part?

This part 560 implements the Outer Continental Shelf Lands Act
(OCSLA), 43 U.S.C. 1331 et seq., as amended, by providing regulations to
foster competition including, but not limited to:
(a) Implementing alternative bidding systems;
(b) Prohibiting joint bidding for development rights by certain
types of joint ventures; and
(c) Establishing diligence requirements for Federal OCS leases.

[76 FR 64623, Oct. 18, 2011. Redesignated at 81 FR 18175, Mar. 30, 2016]

Sec. 560.102 What definitions apply to this part?
What definitions apply to this part?

(a) Terms used in this part have the meaning given in the Act and as
defined in this part.
(b) The following definitions apply to this part:
Area or region means the geographic area or region over which the
BOEM authorized officer has jurisdiction, unless the context in which
those words are used indicates that a different meaning is intended.
BOEM means Bureau of Ocean Energy Management.
Designated official means a representative of DOI subject to the
direction and supervisory authority of the Directors, BOEM, and the
appropriate Regional Manager of the BOEM authorized and empowered to
supervise and direct all oil and gas operations and to perform other
duties prescribed in this chapter.
Director means Director, BOEM, DOI.
DOI means the Department of the Interior, including the Secretary of
the Interior, or his or her delegate.
Federal lease means an agreement which, for consideration,
including, but not limited to, bonuses, rents or royalties conferred,
and covenants to be observed, authorizes a person to explore for, or
develop, or produce (or to do any or all of these) oil and gas, coal,
oil shale, tar sands, and geothermal resources on lands or interests in
lands under Federal jurisdiction.
Gas or Natural Gas means a mixture of hydrocarbons and varying
quantities of non-hydrocarbons that exist in the gaseous phase.
Oil means a mixture of hydrocarbons that exists in a liquid or
gaseous phase in an underground reservoir and which remains or becomes
liquid at atmospheric pressure after passing through surface separating
facilities, including condensate recovered by means other than a
manufacturing process.
Outer Continental Shelf (OCS) means all submerged lands lying
seaward and outside of the area of lands beneath navigable waters as
defined in the Submerged Lands Act (43 U.S.C. 1301-1315) and of which
the subsoil and seabed appertain to the United States and are subject to
its jurisdiction and control.
OCSLA means the Outer Continental Shelf Lands Act, as amended (Act
of August 7, 1953, Ch. 345, 67 Stat. 462, 43 U.S.C. 1331-1356a, as
amended by Pub. L. 95-372, 92 Stat. 629).
Person means a natural person, where so designated, or an entity,
such as a partnership, association, State, political subdivision of a
State or territory, or a private, public, or municipal corporation.
We means the Bureau of Ocean Energy Management (BOEM).
You means the lessee or operating rights owner.

[81 FR 18175, Mar. 30, 2016]

Sec. 560.103 What is BOEM's authority to collect information?

(a) The Paperwork Reduction Act of 1995 (PRA) requires us to inform
you that we may not conduct or sponsor, and you are not required to
respond to, a collection of information unless it displays a currently
valid OMB control number. The information collection under 30 CFR part
560 is either exempt from the PRA (5 CFR 1320.4(a)(2), (c)) or refers to
requirements covered under 30 CFR parts 203 and 556.
(b) You may send comments regarding any aspect of the collection of
information under this part, including suggestions for reducing the
burden, to the Information Collection Clearance Officer, Bureau of Ocean
Energy Management, 45600 Woodland Road, Sterling, VA 20166.

[76 FR 64623, Oct. 18, 2011, as amended at 80 FR 57097, Sept. 22, 2015.
Redesignated at 81 FR 18175, Mar. 30, 2016]

[[Page 490]]

Subpart B_Bidding Systems

General Provisions

Sec. 560.200 What is the purpose of this subpart?

This subpart establishes the bidding systems that we may use to
offer and sell Federal leases for the exploration, development, and
production of oil and gas resources located on the OCS.

[76 FR 64623, Oct. 18, 2011. Redesignated at 81 FR 18175, Mar. 30, 2016]

Sec. 560.201 What definitions apply to this subpart?

Act means the Outer Continental Shelf Deep Water Royalty Relief Act,
Pub. L. 104-58, 43 U.S.C. 1337(3).
Eligible lease means a lease that:
(1) Is issued as part of an OCS lease sale held after November 28,
1995, and before November 28, 2000;
(2) Is located in the Gulf of Mexico in water depths of 200 meters
or deeper;
(3) Lies wholly west of 87 degrees, 30 minutes West longitude; and
(4) Is offered subject to a royalty suspension volume.
Field means an area consisting of a single reservoir or multiple
reservoirs all grouped on, or related to, the same general geological
structural feature and/or stratigraphic trapping condition. Two or more
reservoirs may be in a field, separated vertically by intervening
impervious strata, or laterally by local geologic barriers, or by both.
Highest responsible qualified bidder means a person who has met the
appropriate requirements of 30 CFR part 556, subpart G, and has
submitted a bid higher than any other bids by qualified bidders on the
same tract.
Highest royalty rate means the highest percent rate payable to the
United States, as specified in the lease, in the amount or value of the
production saved, removed, or sold.
Lease period means the time from lease issuance until
relinquishment, expiration, or termination.
Lowest royalty rate means the lowest percent rate payable to the
United States, as specified in the lease, in the amount or value of the
production saved, removed, or sold.
OCS lease sale means the Department of the Interior (DOI) proceeding
by which leases for certain OCS tracts are offered for sale by
competitive bidding and during which bids are received, announced, and
recorded.
Pre-Act lease means a lease that:
(1) Is issued as part of an OCS lease sale held before November 28,
1995;
(2) Is located in the Gulf of Mexico in water depths of 200 meters
or deeper; and
(3) Lies wholly west of 87 degrees, 30 minutes West longitude (see
30 CFR part 203).
Production period means the period during which the amount of oil
and gas produced from a tract (or, if the tract is unitized, the amount
of oil and gas as allocated under a unitization formula) will be
measured for purposes of determining the amount of royalty payable to
the United States.
Qualified bidder means a person who has met the appropriate
requirements of 30 CFR part 556, subpart G.
Royalty rate means the percentage of the amount or value of the
production saved, removed, or sold that is due and payable to the United
States Government.
Royalty suspension (RS) lease means a lease that:
(1) Is issued as part of an OCS lease sale held after November 28,
2000;
(2) Is in locations or planning areas specified in a particular
Notice of OCS Lease Sale; and
(3) Is offered subject to a royalty suspension specified in a Notice
of OCS Lease Sale published in the Federal Register.
Tract means a designation assigned solely for administrative
purposes to a block or combination of blocks that are identified by a
leasing map or an official protraction diagram prepared by the DOI.
Value of production means the value of all oil and gas production
saved, removed, or sold from a tract (or, if the tract is unitized, the
value of all oil and gas production saved, removed, or sold and credited
to the tract under a unitization formula) during a period of production.
The value of production is determined under 30 CFR part 1206.

[76 FR 64623, Oct. 18, 2011. Redesignated at 81 FR 18175, Mar. 30, 2016]

[[Page 491]]

Sec. 560.202 What bidding systems may BOEM use?

We will apply a single bidding system selected from those listed in
this section to each tract included in an OCS lease sale. The following
table lists bidding systems, the bid variables, and characteristics.

------------------------------------------------------------------------
For the bidding system The bid variable is And the characteristics
. . . the . . . are . . .
------------------------------------------------------------------------
(a) Cash bonus bid Cash bonus, The highest responsible
with a fixed royalty qualified bidder will
rate of not less than pay a royalty rate of
12.5 percent, not less than 12.5
percent at the beginning
of the lease period. We
will specify the royalty
rate for each tract
offered in the Notice of
OCS Lease Sale published
in the Federal Register.
(b) Royalty rate bid Royalty rate, We will specify the fixed
with fixed cash amount of cash bonus the
bonus, highest responsible
qualified bidder must
pay in the Notice of OCS
Lease Sale published in
the Federal Register.
(c) Cash bonus bid Cash bonus, (1) We will calculate the
with a sliding royalty rate the highest
royalty rate of not responsible qualified
less than 12.5 bidder must pay using
percent at the either:
beginning of the (i) A sliding-scale
lease period, formula, which relates
the royalty rate to the
adjusted value or volume
of production, or
(ii) A schedule that
establishes the royalty
rate that we will apply
to specified ranges of
the adjusted value or
volume of production.
(2) We will determine the
adjusted value of
production by applying
an inflation factor to
the actual value of
production.
(3) If you are the
successful high bidder,
your lease will include
the sliding-scale
formula or schedule and
will specify the lowest
and highest royalty
rates that will apply.
(4) You will pay a
royalty rate of not less
than 12.5 percent at the
beginning of the lease
period.
(5) We will include the
sliding-scale royalty
formula or schedule,
inflation factor and
procedures for making
the inflation adjustment
and determining the
value or amount of
production in the Notice
of OCS Lease Sale
published in the Federal
Register.
(d) Cash bonus bid Cash bonus, (1) If we award you a
with fixed share of lease as the highest
the net profits of no responsible qualified
less than 30 percent, bidder, you will
determine the amount of
the net profit share
payment to the United
States for each month by
multiplying the net
profit share base times
the net profit share
rate, according to 30
CFR 1220.022. You will
calculate the net profit
share base according to
30 CFR 1220.021.
(2) You will pay a net
profit share of not less
than 30 percent.
(3) We will specify the
capital recovery factor,
as described in 30 CFR
1220.020, and the net
profit share rate, both
of which may vary from
tract to tract, in the
Notice of OCS Lease Sale
published in the Federal
Register.
(e) Cash bonus with Cash bonus, (1) We may suspend or
variable royalty defer royalty for a
rate(s) during one or period, volume, or value
more periods of of production.
production, Notwithstanding
suspensions or
deferrals, we may impose
a minimum royalty. The
suspensions or deferrals
may vary based on prices
or price changes of oil
and/or gas.
(2) You may pay a royalty
rate less than 12.5
percent on production
but not less than zero
percent.
(3) We will specify the
applicable royalty
rates(s) and suspension
or deferral magnitudes,
formulas, or
relationships in the
Notice of OCS Lease Sale
published in the Federal
Register.
(f) Cash bonus with Cash bonus, We will base the royalty
royalty rate(s) based rate on formula(s) or
on formula(s) or schedule(s) specified in
schedule(s) during the Notice of OCS Lease
one or more periods Sale published in the
of production, Federal Register.
(g) Cash bonus with a Cash bonus, Except for periods of
fixed royalty rate of royalty suspension, you
not less than 12.5 will pay a fixed royalty
percent, at the rate of not less than
beginning of the 12.5 percent. If we
lease period, award to you a lease
suspension of under this system, you
royalties for a must calculate the
period, volume, or royalty due during the
value of production, designated period using
or depending upon the rate, formula, or
selected schedule specified in
characteristics of the lease. We will
extraction, and with specify the royalty
suspensions that may rate, formula, or
vary based on the schedule in the Notice
price of production, of OCS Lease Sale
published in the Federal
Register.
------------------------------------------------------------------------

[[Page 492]]

[76 FR 64623, Oct. 18, 2011. Redesignated at 81 FR 18175, Mar. 30, 2016]

Sec. 560.203 What conditions apply to the bidding systems that BOEM uses?

(a) For each of the bidding systems in Sec. 560.110, we will
include an annual rental fee. Other fees and provisions may apply as
well. The Notice of OCS Lease Sale published in the Federal Register
will specify the annual rental and any other fees the highest
responsible qualified bidder must pay and any other provisions.
(b) If we use any deferment or schedule of payments for the cash
bonus bid, we will specify and include it in the Notice of OCS Lease
Sale published in the Federal Register.
(c) For the bidding systems listed in this subpart, if the bid
variable is a cash bonus bid, the highest bid by a qualified bidder
determines the amount of cash bonus to be paid. We will include the
minimum bid level(s) in the Notice of OCS Lease Sale published in the
Federal Register.
(d) For the bidding systems listed in this subpart, if the bid
variable is the royalty rate, the highest bid by a qualified bidder
determines the royalty rate to be paid. We will include the minimum
royalty rate(s) in the Notice of OCS Lease Sale published in the Federal
Register.
(e) We may, by rule, add to or modify the bidding systems listed in
Sec. 560.110, according to the procedural requirements of the OCSLA, 43
U.S.C. 1331 et seq., as amended by Public Law 95-372, 92 Stat. 629.

[76 FR 64623, Oct. 18, 2011. Redesignated at 81 FR 18175, Mar. 30, 2016]

Eligible Leases

Sec. 560.210 How do royalty suspension volumes apply to eligible leases?

Royalty suspension volumes, as specified in section 304 of the Act,
apply to eligible leases that meet the criteria in Sec. 560.113. For
purposes of this section and Sec. Sec. 560.113 through 560.117:
(a) Any volumes of production that are not normally royalty-bearing
under the lease or the regulations (e.g., fuel gas) do not count against
royalty suspension volumes; and
(b) Production includes volumes allocated to a lease under an
approved unit agreement.

[76 FR 64623, Oct. 18, 2011. Redesignated at 81 FR 18175, Mar. 30, 2016]

Sec. 560.211 When does an eligible lease qualify
for a royalty suspension volume?

(a) Your eligible lease will receive a royalty suspension volume as
specified in the Act. The bidding system in Sec. 560.110(g) applies.
(b) Your eligible lease may receive a royalty suspension volume only
if your entire lease is west of 87 degrees, 30 minutes West longitude.

[76 FR 64623, Oct. 18, 2011. Redesignated at 81 FR 18175, Mar. 30, 2016]

Sec. 560.212 How does BOEM assign and monitor royalty suspension volumes
for eligible leases?

(a) We have specified the water depth category for each eligible
lease in the final Notice of OCS Lease Sale Package. The Final Notice of
Sale is published in the Federal Register and the complete Final Notice
of OCS Lease Sale Package is available on the BOEM Web site. Our
determination of water depth for each lease became final when we issued
the lease.
(b) We have specified in the Notice of OCS Lease Sale the royalty
suspension volume applicable to each water depth. The following table
shows the royalty suspension volumes for each eligible lease in million
barrels of oil equivalent (MMBOE):

------------------------------------------------------------------------
Water depth Minimum royalty suspension volume
------------------------------------------------------------------------
(1) 200 to less than 400 meters...... 17.5 MMBOE.
(2) 400 to less than 800 meters...... 52.5 MMBOE.
(3) 800 meters or more............... 87.5 MMBOE.
------------------------------------------------------------------------

[76 FR 64623, Oct. 18, 2011. Redesignated at 81 FR 18175, Mar. 30, 2016]

Sec. 560.213 How long will a royalty suspension volume
for an eligible lease be effective?

A royalty suspension volume for an eligible lease will continue
through the end of the month in which cumulative production from the
leases in a field

[[Page 493]]

entitled to share the royalty suspension volume reaches that volume or
the lease period ends.

[76 FR 64623, Oct. 18, 2011. Redesignated at 81 FR 18175, Mar. 30, 2016]

Sec. 560.214 How do I measure natural gas production on my eligible lease?

You must measure natural gas production on your eligible lease
subject to the royalty suspension volume as follows: 5.62 thousand cubic
feet of natural gas, measured according to 30 CFR part 250, subpart L,
equals one barrel of oil equivalent.

[76 FR 64623, Oct. 18, 2011. Redesignated at 81 FR 18175, Mar. 30, 2016]

Royalty Suspension (RS) Leases

Sec. 560.220 How does royalty suspension apply to leases issued
in a sale held after November 2000?

We may issue leases with suspension of royalties for a period,
volume or value of production, as authorized in section 303 of the Act.
For purposes of this section and Sec. Sec. 560.121 through 560.124:
(a) Any volumes of production that are not normally royalty-bearing
under the lease or the regulations (e.g., fuel gas) do not count against
royalty suspension volumes; and
(b) Production includes volumes allocated to a lease under an
approved unit agreement.

[76 FR 64623, Oct. 18, 2011. Redesignated at 81 FR 18175, Mar. 30, 2016]

Sec. 560.221 When does a lease issued in a sale held after November 2000
get a royalty suspension?

(a) We will specify any royalty suspension for your RS lease in the
Notice of OCS Lease Sale published in the Federal Register for the sale
in which you acquire the RS lease and will repeat it in the lease
document. In addition:
(1) Your RS lease may produce royalty-free the royalty suspension we
specify for your lease, even if the field to which we assign it is
producing.
(2) The royalty suspension we specify in the Notice of OCS Lease
Sale for your lease does not apply to any other leases in the field to
which we assign your RS lease.
(b) You may apply for a supplemental royalty suspension for a
project under 30 CFR part 203, if your lease is located:
(1) In the Gulf of Mexico, in water 200 meters or deeper, and wholly
west of 87 degrees, 30 minutes West longitude; or
(2) Offshore of Alaska.
(c) Your RS lease retains the royalty suspension with which we
issued it even if we deny your application for more relief.

[76 FR 64623, Oct. 18, 2011. Redesignated at 81 FR 18175, Mar. 30, 2016]

Sec. 560.222 How long will a royalty suspension volume be effective
for a lease issued in a sale held after November 2000?

(a) The royalty suspension volume for your RS lease will continue
through the end of the month in which cumulative production from your
lease reaches the applicable royalty suspension volume or the lease
period ends.
(b)(1) Notwithstanding any royalty suspension volume under this
subpart, you must pay royalty at the lease stipulated rate on:
(i) Any oil produced for any period stipulated in the lease during
which the arithmetic average of the daily closing price on the New York
Mercantile Exchange (NYMEX) for light sweet crude oil exceeds the
applicable threshold price of $36.39 per barrel, adjusted annually after
calendar year 2007 for inflation unless the lease terms prescribe a
different price threshold.
(ii) Any natural gas produced for any period stipulated in the lease
during which the arithmetic average of the daily closing price on the
NYMEX for natural gas exceeds the applicable threshold price of $4.55
per MMBtu, adjusted annually after calendar year 2007 for inflation
unless the lease terms prescribe a different price threshold.
(iii) Determine the threshold price for any calendar year after 2007
by adjusting the threshold price in the previous year by the percentage
that the implicit price deflator for the gross domestic product, as
published by the Department of Commerce, changed during the calendar
year.
(2) You must pay any royalty due under this paragraph, plus late
payment interest under 30 CFR 1218.54, no

[[Page 494]]

later than 90 days after the end of the period for which royalty is
owed.
(3) Any production on which you must pay royalty under this
paragraph will count toward the production volume determined under
Sec. Sec. 560.120 through 560.124.
(c) If you must pay royalty on any product (either oil or natural
gas) for any period under paragraph (b) of this section, you must
continue to pay royalty on that product during the next succeeding
period of the same length until the arithmetic average of the daily
closing NYMEX prices for that product for that period can be determined.
If the arithmetic average of the daily closing prices for that product
for that period is less than the threshold price stipulated in the
lease, you are entitled to a credit or refund of royalties paid for that
period with interest under applicable law.

[76 FR 64623, Oct. 18, 2011. Redesignated at 81 FR 18175, Mar. 30, 2016]

Sec. 560.223 How do I measure natural gas production for a lease issued
in a sale held after November 2000?

You must measure natural gas production subject to the royalty
suspension volume for your lease as follows: 5.62 thousand cubic feet of
natural gas, measured according to 30 CFR part 250, subpart L, equals
one barrel of oil equivalent.

[76 FR 64623, Oct. 18, 2011. Redesignated at 81 FR 18175, Mar. 30, 2016]

Sec. 560.224 How will royalty suspension apply if BOEM assigns a lease
issued in a sale held after November 2000 to a field that has a pre-Act lease?

(a) We will assign your lease that has a qualifying well (under 30
CFR part 250, subpart A) to an existing field or designate a new field
and will notify you and other affected lessees and operating rights
holders in the field of that assignment.
(1) Within 15 days of the final notification, you or any of the
other affected lessees or operating rights holders may file a written
request with the Director for reconsideration, accompanied by a
Statement of Reasons.
(2) The Director will respond in writing either affirming or
reversing the assignment decision. The Director's decision is the final
action of the Department of the Interior and is not subject to appeal to
the Interior Board of Land Appeals under 30 CFR part 590 and 43 CFR part
4.
(b) If we establish a royalty suspension volume for a field as a
result of an approved application for royalty relief submitted for a
pre-Act lease under 30 CFR part 203, then:
(1) Royalty-free production from your RS lease shares from and
counts as part of any royalty suspension volume under Sec. 560.114(d)
for the field to which we assign your lease; and
(2) Your RS lease may continue to produce royalty-free up to the
royalty suspension we specified for your lease, even if the field to
which we assign your RS lease has produced all of its royalty suspension
volume.
(c) Your lease may share in a suspension volume larger than the
royalty suspension with which we issued it and to the extent we grant a
larger volume in response to an application by a pre-Act lease submitted
under 30 CFR part 203. To share in any larger royalty suspension volume,
you must file an application described in 30 CFR part 203 (Sec. Sec.
203.71 and 203.83). In no case will royalty-free production for your RS
lease be less than the royalty suspension specified for your lease.

[76 FR 64623, Oct. 18, 2011. Redesignated at 81 FR 18175, Mar. 30, 2016]

Bidding System Selection Criteria

Sec. 560.230 What criteria does BOEM use for selecting bidding systems
and bidding system components?

In analyzing the application of one of the bidding systems listed in
Sec. 560.110 to tracts selected for any OCS lease sale, we may, at our
discretion, consider the following purposes and policies. We recognize
that each of the purposes and policies may not be specifically
applicable to the selection process for a particular bidding system or
tract, or may present a conflict that we will have to resolve in the
process of bidding system selection. The order of listing does not
denote a ranking.
(a) Providing fair return to the Federal Government;
(b) Increasing competition;

[[Page 495]]

(c) Ensuring competent and safe operations;
(d) Avoiding undue speculation;
(e) Avoiding unnecessary delays in exploration, development, and
production;
(f) Discovering and recovering oil and gas;
(g) Developing new oil and gas resources in an efficient and timely
manner;
(h) Limiting the administrative burdens on Government and industry;
and
(i) Providing an opportunity to experiment with various bidding
systems to enable us to identify those most appropriate for the
satisfaction of the objectives of the United States in OCS lease sales.

Subpart C_Operating Allowances

Sec. 560.300 Operating allowances.

Notwithstanding any other provision in the regulations in this part,
BOEM may issue a lease containing an operating allowance when so
specified in the final notice of sale and the lease. The allowance
amount or formula will be specified in the final notice of sale and in
the lease.

[81 FR 18175, Mar. 10, 2016]

Subpart D [Reserved]

Subpart E_Electronic Filings

Source: 81 FR 18176, Mar. 30, 2016, unless otherwise noted.

Sec. 560.500 Electronic document and data transmissions.

(a) BOEM may notify you that it will allow or request you to submit
the following information electronically through BOEM's secure
electronic filing system, through an alternate secure electronic filing
system supported and maintained by the Department, or through some other
electronic filing system that BOEM has approved for this purpose:
(1) Any document(s) or information described in the Qualifications
section of part 556 of this chapter, as specified in subpart E. Such
information would include, but not be limited to, the official name of
the qualifying person, its legal and business address or addresses, its
legal form and status, and the names and contact information of a person
or organization authorized to act on the person's behalf.
(2) Any document(s) or information required to obtain BOEM's
approval of an assignment or sublease, including any form or instrument
that creates or transfers ownership of a lease interest.
(3) Any document(s) or information required to obtain BOEM's
approval of your relinquishment of all, or any aliquot part of your
lease, as specified in Sec. 556.1101 of this chapter.
(4) Any document(s) creating, transferring or assigning economic
interests, as specified in Sec. Sec. 556.715 and 556.808 of this
chapter.
(5) Any document(s) related to a bond, U.S. Treasury note or other
security provided to BOEM, which is required to guarantee your
compliance with terms and conditions of a lease.
(6) Any document(s) or information necessary to bid for an OCS
lease.
(7) Any forms, document(s) or information necessary to determine
worst case oil-spill discharge volume(s), or to provide evidence
demonstrating oil spill financial responsibility, or to guarantee such
financial responsibility or to comply with any other requirements of the
Oil Spill Financial Responsibility Program, as described in part 553 of
this chapter.
(b) BOEM reserves the right to require the electronic filing of any
document(s) or information addressed in paragraph (a)(5) of this section
upon a 90-day notice published in the Federal Register; if BOEM mandates
that you transmit such document(s) or information electronically, the
Federal Register notice will specify the filing details necessary to
comply with this regulation.
(c) In the event BOEM sends documents to you in a secure electronic
format, you may either return the document(s) in an electronic format
utilizing the same secure transmission mechanism or print the
document(s) and return them.
(d) BOEM may electronically acknowledge, approve, sign, or execute
any document(s) referenced in this section.

[[Page 496]]

Sec. 560.501 How long will the confidentiality of electronic document
and data transmissions be maintained?

The confidentiality of any electronically submitted information will
be maintained for the same proprietary term that would apply to the
corresponding non-electronic confidential submission, pursuant to Sec.
556.104(b) of this chapter.

Sec. 560.502 Are electronically filed document transmissions legally binding?

Any document or information referenced in Sec. 560.500 which is
submitted to BOEM through a secure electronic filing system that is
approved by BOEM will be legally binding, without the need for a paper
copy thereof.

PART 570_NONDISCRIMINATION IN THE OUTER CONTINENTAL SHELF--Table of Contents

Sec.
570.1 Purpose.
570.2 Application of this part.
570.3 Definitions.
570.4 Discrimination prohibited.
570.5 Complaint.
570.6 Process.
570.7 Remedies.

Authority: 43 U.S.C. 1863.

Source: 76 FR 64623, Oct. 18, 2011, unless otherwise noted.

Sec. 570.1 Purpose.

Sec. 570.2 Application of this part.

Sec. 570.3 Definitions.

As used in this part, the following terms shall have the following
meaning:
Contract means any business agreement or arrangement (in which the
parties do not stand in the relationship of employer and employee)
between a lessee and any person which creates an obligation to provide
goods, services, facilities, or property.
Lessee means the party authorized by a lease, grant of right-of-way,
or an approved assignment thereof to explore, develop, produce, or
transport oil, gas, or other minerals or materials in the OCS pursuant
to the Act and this part.
Person means a person or company, including but not limited to, a
corporation, partnership, association, joint stock venture, trust,
mutual fund, or any receiver, trustee in bankruptcy, or other official
acting in a similar capacity for such company.
Subcontract means any business agreement or arrangement (in which
the parties do not stand in the relationship of employer and employee)
between a lessee's contractor and any person other than a lessee that is
in any way related to the performance of any one or more contracts.

Sec. 570.4 Discrimination prohibited.

No contract or subcontract to which this part applies shall be
denied to or withheld from any person on the grounds of race, creed,
color, national origin, or sex.

Sec. 570.5 Complaint.

[[Page 497]]

(b) The complaint referred to in paragraph (a) of this section shall
be accompanied by such evidence as may be available to a person and
which is relevant to the complaint including affidavits and other
documents.
(c) Whenever any person files a complaint under this part, the
Regional Director with whom such complaint is filed shall give written
notice of such filing to all persons cited in the complaint no later
than 10 days after receipt of such complaint. Such notice shall include
a statement describing the alleged incident of discrimination, including
the date and the names of persons involved in it.

Sec. 570.6 Process.

Whenever a Regional Director determines on the basis of any
information, including that which may be obtained under Sec. 570.5 of
this part, that a violation of or failure to comply with any provision
of this subpart probably occurred, the Regional Director shall undertake
to afford the complainant and the person(s) alleged to have violated the
provisions of this part an opportunity to engage in informal
consultations, meetings, or any other form of communications for the
purpose of resolving the complaint. In the event such communications or
consultations result in a mutually satisfactory resolution of the
complaint, the complainant and all persons cited in the complaint shall
notify the Regional Director in writing of their agreement to such
resolution. If either the complainant or the person(s) alleged to have
wrongfully discriminated fail to provide such written notice within a
reasonable period of time, the Regional Director must proceed in
accordance with the provisions of 30 CFR part 550, subpart N.

Sec. 570.7 Remedies.

In addition to the penalties available under 30 CFR part 550,
subpart N, the Director may invoke any other remedies available to him
or her under the Act or regulations for the lessee's failure to comply
with provisions of the Act, regulations, or lease.

PART 580_PROSPECTING FOR MINERALS OTHER THAN OIL, GAS, AND SULPHUR
ON THE OUTER CONTINENTAL SHELF--Table of Contents

Subpart A_General Information

Sec.
580.1 What definitions apply to this part?
580.2 What is the purpose of this part?
580.3 What requirements must I follow when I conduct prospecting or
research activities?
580.4 What activities are not covered by this part?

Subpart B_How To Apply for a Permit or File a Notice

580.10 What must I do before I may conduct prospecting activities?
580.11 What must I do before I may conduct scientific research?
580.12 What must I include in my application or notification?
580.13 Where must I send my application or notification?

Subpart C_Obligations Under This Part

Prohibitions and Requirements

580.20 What must I not do in conducting Geological and Geophysical (G&G)
prospecting or scientific research?
580.21 What must I do in conducting G&G prospecting or scientific
research?
580.22 What must I do when seeking approval for modifications?
580.23 How must I cooperate with inspection activities?
580.24 What reports must I file?

Interrupted Activities

580.25 When may BOEM require me to stop activities under this part?
580.26 When may I resume activities?
580.27 When may BOEM cancel my permit?
580.28 May I relinquish my permit?

Environmental Issues

580.29 Will BOEM monitor the environmental effects of my activity?
580.30 What activities will not require environmental analysis?
580.31 Whom will BOEM notify about environmental issues?

Penalties and Appeals

580.32 What penalties may I be subject to?
580.33 How can I appeal a penalty?
580.34 How can I appeal an order or decision?

[[Page 498]]

Subpart D_Data Requirements

Geological Data and Information

580.40 When do I notify BOEM that geological data and information are
available for submission, inspection, and selection?
580.41 What types of geological data and information must I submit to
BOEM?
580.42 When geological data and information are obtained by a third
party, what must we both do?

ysical Data and Information

580.50 When do I notify BOEM that geophysical data and information are
available for submission, inspection, and selection?
580.51 What types of geophysical data and information must I submit to
BOEM?
580.52 When geophysical data and information are obtained by a third
party, what must we both do?

Reimbursement

580.60 Which of my costs will be reimbursed?
580.61 Which of my costs will not be reimbursed?

Protections

580.70 What data and information will be protected from public
disclosure?
580.71 What is the timetable for release of data and information?
580.72 What procedure will BOEM follow to disclose acquired data and
information to a contractor for reproduction, processing, and
interpretation?
580.73 Will BOEM share data and information with coastal States?

Subpart E_Information Collection

580.80 Paperwork Reduction Act statement--information collection.

Source: 76 FR 64623, Oct. 18, 2011, unless otherwise noted.

Subpart A_General Information

Sec. 580.1 What definitions apply to this part?

Definitions in this part have the following meaning:
Act means the OCS Lands Act, as amended (43 U.S.C. 1331 et seq.).
Adjacent State means with respect to any activity proposed,
conducted, or approved under this part, any coastal State(s):
(1) That is used, or is scheduled to be used, as a support base for
geological and geophysical (G&G) prospecting or scientific research
activities; or
(2) In which there is a reasonable probability of significant effect
on land or water uses from such activity.
Analyzed geological information means data collected under a permit
or a lease that have been analyzed. Some examples of analysis include,
but are not limited to, identification of lithologic and fossil content,
core analyses, laboratory analyses of physical and chemical properties,
well logs or charts, results from formation fluid tests, and
descriptions of mineral occurrences or hazardous conditions.
Archaeological interest means capable of providing scientific or
humanistic understandings of past human behavior, cultural adaptation,
and related topics through the application of scientific or scholarly
techniques, such as controlled observation, contextual measurement,
controlled collection, analysis, interpretation, and explanation.
Archaeological resource means any material remains of human life or
activities that are at least 50 years of age and are of archaeological
interest.
Coastal environment means the physical, atmospheric, and biological
components, conditions, and factors that interactively determine the
productivity, state, condition, and quality of the terrestrial ecosystem
from the shoreline inward to the boundaries of the coastal zone.
Coastal zone means the coastal waters (including the lands therein
and thereunder) and the adjacent shorelands (including the waters
therein and thereunder) that are strongly influenced by each other and
in proximity to the shorelands of the several coastal States. The
coastal zone includes islands, transition and intertidal areas, salt
marshes, wetlands, and beaches. The coastal zone extends seaward to the
outer limit of the United States territorial sea and extends inland from
the shorelines to the extent necessary to control shorelands, the uses
of

[[Page 499]]

which have a direct and significant impact on the coastal waters, and
the inward boundaries of which may be identified by the several coastal
States, under the authority in section 305(b)(1) of the Coastal Zone
Management Act of 1972.
Coastal Zone Management Act means the Coastal Zone Management Act of
1972, as amended (16 U.S.C. 1451 et seq.).
Data means facts and statistics, measurements, or samples that have
not been analyzed, processed, or interpreted.
Deep stratigraphic test means drilling that involves the penetration
into the sea bottom of more than 500 feet (152 meters).
Director means the Director of the Bureau of Ocean Energy
Management, U.S. Department of the Interior, or an official authorized
to act on the Director's behalf.
Geological and geophysical (G&G) prospecting activities mean the
commercial search for mineral resources other than oil, gas, or sulphur.
Activities classified as prospecting include, but are not limited to:
(1) Geological and geophysical marine and airborne surveys where
magnetic, gravity, seismic reflection, seismic refraction, or the
gathering through coring or other geological samples are used to detect
or imply the presence of hard minerals; and
(2) Any drilling, whether on or off a geological structure.
Geological and geophysical (G&G) scientific research activities mean
any investigations related to hard minerals that are conducted on the
OCS for academic or scientific research. These investigations would
involve gathering and analyzing geological, geochemical, or geophysical
data and information that are made available to the public for
inspection and reproduction at the earliest practical time. The term
does not include commercial G&G exploration or commercial G&G
prospecting activities.
Geological data and information means data and information gathered
through or derived from geological and geochemical techniques, e.g.,
coring and test drilling, well logging, bottom sampling, or other
physical sampling or chemical testing process.
Geological sample means a collected portion of the seabed, the
subseabed, or the overlying waters acquired while conducting prospecting
or scientific research activities.
Geophysical data and information means any data or information
gathered through or derived from geophysical measurement or sensing
techniques (e.g., gravity, magnetic, or seismic).
Governor means the Governor of a State or the person or entity
lawfully designated by or under State law to exercise the powers granted
to a Governor under the Act.
Hard minerals mean any minerals found on or below the surface of the
seabed except for oil, gas, or sulphur.
Interpreted geological information means the knowledge, often in the
form of schematic cross sections, 3-dimensional representations, and
maps, developed by determining the geological significance of geological
data and analyzed and processed geologic information.
Interpreted geophysical information means knowledge, often in the
form of seismic cross sections, 3-dimensional representations, and maps,
developed by determining the geological significance of geophysical data
and processed geophysical information.
Lease means, depending upon the requirements of the context, either:
(1) An agreement issued under section 8 or maintained under section
6 of the Act that authorizes mineral exploration, development and
production; or
(2) The area covered by an agreement specified in paragraph (1) of
this definition.
Material remains means physical evidence of human habitation,
occupation, use, or activity, including the site, location, or context
in which evidence is situated.
Minerals mean all minerals authorized by an Act of Congress to be
produced from ``public lands'' as defined in section 103 of the Federal
Land Policy and Management Act of 1976 (43 U.S.C. 1702). The term
includes oil, gas, sulphur, geopressured-geothermal and associated
resources.
Notice means a written statement of intent to conduct G&G scientific
research that is:

[[Page 500]]

(1) Related to hard minerals on the OCS; and
(2) Not covered under a permit.
Oil, gas, and sulphur means oil, gas, and sulphur, geopressured-
geothermal and associated resources, including gas hydrates.
Outer Continental Shelf (OCS) means all submerged lands:
(1) That lie seaward and outside of the area of lands beneath
navigable waters as defined in section 2 of the Submerged Lands Act (43
U.S.C. 1301); and
(2) Whose subsoil and seabed belong to the United States and are
subject to its jurisdiction and control.
Permit means the contract or agreement, other than a lease, issued
under this part. The permit gives a person the right, under appropriate
statutes, regulations, and stipulations, to conduct on the OCS:
(1) Geological prospecting for hard minerals;
(2) Geophysical prospecting for hard minerals;
(3) Geological scientific research; or
(4) Geophysical scientific research.
Permittee means the person authorized by a permit issued under this
part to conduct activities on the OCS.
Person means:
(1) A citizen or national of the United States;
(2) An alien lawfully admitted for permanent residence in the United
States as defined in section 8 U.S.C. 1101(a)(20);
(3) A private, public, or municipal corporation organized under the
laws of the United States or of any State or territory thereof, and
association of such citizens, nationals, resident aliens or private,
public, or municipal corporations, States, or political subdivisions of
States; or
(4) Anyone operating in a manner provided for by treaty or other
applicable international agreements. The term does not include Federal
agencies.
Processed geological or geophysical information means data collected
under a permit and later processed or reprocessed.
(1) Processing involves changing the form of data as to facilitate
interpretation. Some examples of processing operations may include, but
are not limited to:
(i) Applying corrections for known perturbing causes;
(ii) Rearranging or filtering data; and
(iii) Combining or transforming data elements.
(2) Reprocessing is the additional processing other than ordinary
processing used in the general course of evaluation. Reprocessing
operations may include varying identified parameters for the detailed
study of a specific problem area.
Secretary means the Secretary of the Interior or a subordinate
authorized to act on the Secretary's behalf.
Shallow test drilling means drilling into the sea bottom to depths
less than those specified in the definition of a deep stratigraphic
test.
Significant archaeological resource means those archaeological
resources that meet the criteria of significance for eligibility of the
National Register of Historic Places as defined in 36 CFR 60.4, or its
successor.
Third party means any person other than the permittee or a
representative of the United States, including all persons who obtain
data or information acquired under a permit from the permittee, or from
another third party, by sale, trade, license agreement, or other means.
You means a person who applies for and/or obtains a permit, or files
a notice to conduct G&G prospecting or scientific research related to
hard minerals on the OCS.

Sec. 580.2 What is the purpose of this part?

The purpose of this part is to:
(a) Allow you to conduct prospecting activities or scientific
research activities on the OCS in Federal waters related to hard
minerals on unleased lands or on lands under lease to a third party.
(b) Ensure that you carry out prospecting activities or scientific
research activities in a safe and environmentally sound manner so as to
prevent harm or damage to, or waste of, any natural resources (including
any hard minerals in areas leased or not leased), any life (including
fish and other aquatic life), property, or the

[[Page 501]]

marine, coastal, or human environment.
(c) Inform you and third parties of your legal and contractual
obligations.
(d) Inform you and third parties of:
(1) The U.S. Government's rights to access G&G data and information
collected under permit on the OCS;
(2) Reimbursement we will make for data and information that are
submitted; and
(3) The proprietary terms of data and information that we retain.

Sec. 580.3 What requirements must I follow when I conduct prospecting
or research activities?

You must conduct G&G prospecting activities or scientific research
activities under this part according to:
(a) The Act;
(b) The regulations in this part;
(c) Orders of the Director/Regional Director (RD); and
(d) Other applicable statutes, regulations, and amendments.

Sec. 580.4 What activities are not covered by this part?

This part does not apply to:
(a) G&G prospecting activities conducted by, or on behalf of, the
lessee on a lease on the OCS;
(b) Federal agencies;
(c) Postlease activities for mineral resources other than oil, gas,
and sulphur, which are covered by regulations at 30 CFR parts 582 and
282; and
(d) G&G exploration or G&G scientific research activities related to
oil, gas, and sulphur, including gas hydrates, which are covered by
regulations at 30 CFR parts 551 and 251.

Subpart B_How To Apply for a Permit or File a Notice

Sec. 580.10 What must I do before I may conduct prospecting activities?

You must have a BOEM-approved permit to conduct G&G prospecting
activities, including deep stratigraphic tests, for hard minerals. If
you conduct both G&G prospecting activities, you must have a separate
permit for each.

Sec. 580.11 What must I do before I may conduct scientific research?

You may conduct G&G scientific research activities related to hard
minerals on the OCS only after you obtain a BOEM-approved permit or file
a notice.
(a) Permit. You must obtain a permit if the research activities you
want to conduct involve:
(1) Using solid or liquid explosives;
(2) Drilling a deep stratigraphic test; or
(3) Developing data and information for proprietary use or sale.
(b) Notice. If you conduct research activities (including federally
funded research) not covered by paragraph (a) of this section, you must
file a notice with the regional director at least 30 days before you
begin. If you cannot file a 30-day notice, you must provide oral
notification before you begin and follow up in writing. You must also
inform BOEM in writing when you conclude your work.

Sec. 580.12 What must I include in my application or notification?

(a) Permits. You must submit to the Regional Director a signed
original and three copies of the permit application form (Form BOEM-
0134) at least 30 days before the startup date for activities in the
permit area. If unusual circumstances prevent you from meeting this
deadline, you must immediately contact the Regional Director to arrange
an acceptable deadline. The form includes names of persons; the type,
location, purpose, and dates of activity; and environmental and other
information. A nonrefundable service fee of $2,012 must be paid
electronically through Pay.gov at: https://www.pay.gov/paygov/ and you
must include a copy of the Pay.gov confirmation receipt page with your
application.
(b) Disapproval of permit application. If we disapprove your
application for a permit, the RD will explain the reasons for the
disapproval and what you must do to obtain approval.
(c) Notices. You must sign and date a notice that includes:
(1) The name(s) of the person(s) who will conduct the proposed
research;

[[Page 502]]

(2) The name(s) of any other person(s) participating in the proposed
research, including the sponsor;
(3) The type of research and a brief description of how you will
conduct it;
(4) A map, plat, or chart, that shows the location where you will
conduct research;
(5) The proposed projected starting and ending dates for your
research activity;
(6) The name, registry number, registered owner, and port of
registry of vessels used in the operation;
(7) The earliest practical time you expect to make the data and
information resulting from your research activity available to the
public;
(8) Your plan of how you will make the data and information you
collect available to the public;
(9) A statement that you and others involved will not sell or
withhold the data and information resulting from your research; and
(10) At your option, the nonexclusive use agreement for scientific
research attachment to Form BOEM-0134. (If you submit this agreement,
you do not have to submit the material required in paragraphs (c)(7),
(c)(8), and (c)(9) of this section.)

Sec. 580.13 Where must I send my application or notification?

You must apply for a permit or file a notice at one of the following
locations:

------------------------------------------------------------------------
For the OCS off the . . . Apply to . . .
------------------------------------------------------------------------
(a) State of Alaska.......... Regional Supervisor for Resource
Evaluation, Bureau of Ocean Energy
Management, Alaska OCS Region, 3801
Centerpoint Drive, Suite 500, Anchorage,
AK 99503.
(b) Atlantic Coast, Gulf of Regional Supervisor for Resource
Mexico, Puerto Rico, or U.S. Evaluation, Bureau of Ocean Energy
territories in the Caribbean Management, Gulf of Mexico OCS Region,
Sea. 1201 Elmwood Park Boulevard, New
Orleans, LA 70123-2394.
(c) States of California, Regional Supervisor for Resource
Oregon, Washington, Hawaii, Evaluation, Bureau of Ocean Energy
or U.S. territories in the Management, Pacific OCS Region, 760
Pacific Ocean. Paseo Camarillo, Suite 102 (CM 102),
Camarillo, CA 93010.
------------------------------------------------------------------------

[76 FR 64623, Oct. 18, 2011, as amended at 80 FR 57097, Sept. 22, 2015]

Subpart C_Obligations Under This Part

Prohibitions and Requirements

Sec. 580.20 What must I not do in conducting Geological and Geophysical
(G&G) prospecting or scientific research?

While conducting G&G prospecting or scientific research activities
under a permit or notice, you must not:
(a) Interfere with or endanger operations under any lease, right-of-
way, easement, right-of-use, notice, or permit issued or maintained
under the Act;
(b) Cause harm or damage to life (including fish and other aquatic
life), property, or the marine, coastal, or human environment;
(c) Cause harm or damage to any mineral resources (in areas leased
or not leased);
(d) Cause pollution;
(e) Disturb archaeological resources;
(f) Create hazardous or unsafe conditions;
(g) Unreasonably interfere with or cause harm to other uses of the
area; or
(h) Claim any oil, gas, sulphur, or other minerals you discover
while conducting operations under a permit or notice.

Sec. 580.21 What must I do in conducting G&G prospecting
or scientific research?

While conducting G&G prospecting or scientific research activities
under a permit or notice, you must:
(a) Immediately report to the Regional Director if you:
(1) Detect hydrocarbon or any other mineral occurrences;
(2) Detect environmental hazards that imminently threaten life and
property; or
(3) Adversely affect the environment, aquatic life, archaeological
resources, or other uses of the area where you are

[[Page 503]]

prospecting or conducting scientific research activities.
(b) Consult and coordinate your G&G activities with other users of
the area for navigation and safety purposes.
(c) If you conduct shallow test drilling or deep stratigraphic test
drilling activities, you must use the best available and safest
technologies that the Regional Director considers economically feasible.

Sec. 580.22 What must I do when seeking approval for modifications?

Before you begin modified operations, you must submit a written
request describing the modifications and receive the Regional Director's
oral or written approval. If circumstances preclude a written request,
you must make an oral request and follow up in writing.

Sec. 580.23 How must I cooperate with inspection activities?

(a) You must allow our representatives to inspect your G&G
prospecting or any scientific research activities that are being
conducted under a permit. They will determine whether operations are
adversely affecting the environment, aquatic life, archaeological
resources, or other uses of the area.
(b) BOEM will reimburse you for food, quarters, and transportation
that you provide for our representatives if you send in your
reimbursement request to the region that issued the permit within 90
days of the inspection.

Sec. 580.24 What reports must I file?

(a) You must submit status reports on a schedule specified in the
permit and include a daily log of operations.
(b) You must submit a final report of G&G prospecting or scientific
research activities under a permit within 30 days after you complete
acquisition activities under the permit. You may combine the final
report with the last status report and must include each of the
following:
(1) A description of the work performed.
(2) Charts, maps, plats and digital navigation data in a format
specified by the Regional Director, showing the areas and blocks in
which any G&G prospecting or permitted scientific research activities
were conducted. Identify the lines of geophysical traverses and their
locations including a reference sufficient to identify the data produced
during each activity.
(3) The dates on which you conducted the actual prospecting or
scientific research activities.
(4) A summary of any:
(i) Hard mineral, hydrocarbon, or sulphur occurrences encountered;
(ii) Environmental hazards; and
(iii) Adverse effects of the G&G prospecting or scientific research
activities on the environment, aquatic life, archaeological resources,
or other uses of the area in which the activities were conducted.
(5) Other descriptions of the activities conducted as specified by
the Regional Director.

Interrupted Activities

Sec. 580.25 When may BOEM require me to stop activities under this part?

(a) We may temporarily stop prospecting or scientific research
activities under a permit when the Regional Director determines that:
(1) Activities pose a threat of serious, irreparable, or immediate
harm. This includes damage to life (including fish and other aquatic
life), property, and any minerals (in areas leased or not leased), to
the marine, coastal, or human environment, or to an archaeological
resource;
(2) You failed to comply with any applicable law, regulation, order
or provision of the permit. This would include our required submission
of reports, well records or logs, and G&G data and information within
the time specified; or
(3) Stopping the activities is in the interest of National security
or defense.
(b) The Regional Director will advise you either orally or in
writing of the procedures to temporarily stop activities. We will
confirm an oral notification in writing and deliver all written
notifications by courier or certified/registered mail. You must stop all
activities under a permit as soon as you receive an oral or written
notification.

[[Page 504]]

Sec. 580.26 When may I resume activities?

The Regional Director will advise you when you may start your permit
activities again.

Sec. 580.27 When may BOEM cancel my permit?

Sec. 580.28 May I relinquish my permit?

(a) You may relinquish your permit at any time by advising the
Regional Director by certified or registered mail 30 days in advance.
(b) After you relinquish your permit, you are still responsible for
proper abandonment of any drill sites according to the requirements of
30 CFR 251.7(b)(8). You must also comply with all other obligations
specified in this part or in the permit.

Environmental Issues

Sec. 580.29 Will BOEM monitor the environmental effects of my activity?

We will evaluate the potential of proposed prospecting or scientific
research activities for adverse impact on the environment to determine
the need for mitigation measures.

Sec. 580.30 What activities will not require environmental analysis?

We anticipate that activities of the type listed below typically
will not cause significant environmental impact and will normally be
categorically excluded from additional environmental analysis. The types
of activities include:
(a) Gravity and magnetometric observations and measurements;
(b) Bottom and subbottom acoustic profiling or imaging without the
use of explosives;
(c) Hard minerals sampling of a limited nature such as shallow test
drilling;
(d) Water and biotic sampling, if the sampling does not adversely
affect shellfish beds, marine mammals, or an endangered species or if
permitted by the National Marine Fisheries Service or another Federal
agency;
(e) Meteorological observations and measurements, including the
setting of instruments;
(f) Hydrographic and oceanographic observations and measurements,
including the setting of instruments;
(g) Sampling by box core or grab sampler to determine seabed
geological or geotechnical properties;
(h) Television and still photographic observation and measurements;
(i) Shipboard hard mineral assaying and analysis; and
(j) Placement of positioning systems, including bottom transponders
and surface and subsurface buoys reported in Notices to Mariners.

Sec. 580.31 Whom will BOEM notify about environmental issues?

(a) In cases where Coastal Zone Management Act consistency review is
required, the Director will notify the Governor of each adjacent State
with a copy of the application for a permit immediately upon the
submission for approval.
(b) In cases where an environmental assessment is to be prepared,
the Director will invite the Governor of each adjacent State to review
and provide comments regarding the proposed activities. The Director's
invitation to provide comments will allow the Governor a specified
period of time to comment.
(c) When a permit is issued, the Director will notify affected
parties including each affected coastal State, Federal agency, local
government, and special interest organization that has expressed an
interest.

Penalties and Appeals

Sec. 580.32 What penalties may I be subject to?

(a) Penalties for noncompliance under a permit. You are subject to
the penalty provisions of section 24 of the Act (43

[[Page 505]]

U.S.C. 1350) and the procedures contained in 30 CFR part 550, subpart N
for noncompliance with:
(1) Any provision of the Act;
(2) Any provisions of a G&G or drilling permit; or
(3) Any regulation or order issued under the Act.
(b) Penalties under other laws and regulations. The penalties
prescribed in this section are in addition to any other penalty imposed
by any other law or regulation.

Sec. 580.33 How can I appeal a penalty?

See 30 CFR part 550.1409 and 30 CFR part 590, subpart A, for
instructions on how to appeal any decision assessing a civil penalty
under 43 U.S.C. 1350 and 30 CFR part 550, subpart A.

Sec. 580.34 How can I appeal an order or decision?

See 30 CFR part 590, subpart A, for instructions on how to appeal an
order or decision.

Subpart D_Data Requirements

Geological Data and Information

Sec. 580.40 When do I notify BOEM that geological data and information
are available for submission, inspection, and selection?

(a) You must notify the Regional Director, in writing, when you
complete the initial analysis, processing, or interpretation of any
geological data and information. Initial analysis and processing are the
stages of analysis or processing where the data and information first
become available for in-house interpretation by the permittee or become
available commercially to third parties via sale, trade, license
agreement, or other means.
(b) The Regional Director may ask if you have further analyzed,
processed, or interpreted any geological data and information. When
asked, you must respond to us in writing within 30 days.
(c) The Regional Director may ask you or a third party to submit the
analyzed, processed, or interpreted geologic data and information for us
to inspect or permanently retain. You must submit the data and
information within 30 days after such a request.

Sec. 580.41 What types of geological data and information
must I submit to BOEM?

Unless the Regional Director specifies otherwise, you must submit
geological data and information that include:
(a) An accurate and complete record of all geological (including
geochemical) data and information describing each operation of analysis,
processing, and interpretation;
(b) Paleontological reports identifying by depth any microscopic
fossils collected, including the reference datum to which
paleontological sample depths are related and, if the Regional Director
requests, washed samples, that you maintain for paleontological
determinations;
(c) Copies of well logs or charts in a digital format, if available;
(d) Results and data obtained from formation fluid tests;
(e) Analyses of core or bottom samples and/or a representative cut
or split of the core or bottom sample;
(f) Detailed descriptions of any hydrocarbons or other minerals or
hazardous conditions encountered during operations, including near
losses of well control, abnormal geopressures, and losses of
circulation; and
(g) Other geological data and information that the RD may specify.

Sec. 580.42 When geological data and information are obtained
by a third party, what must we both do?

A third party may obtain geological data and information from a
permittee, or from another third party, by sale, trade, license
agreement, or other means. If this happens:
(a) The third-party recipient of the data and information assumes
the obligations under this part, except for the notification provisions
of Sec. 580.40(a) and is subject to the penalty provisions of Sec.
580.32(a)(1) and 30 CFR part 550, subpart N; and
(b) A permittee or third party that sells, trades, licenses, or
otherwise provides data and information to a third party must advise the
recipient, in writing, that accepting these obligations is a condition
precedent of the sale, trade, license, or other agreement; and

[[Page 506]]

(c) Except for license agreements, a permittee or third party that
sells, trades, or otherwise provides data and information to a third
party must advise the Regional Director in writing within 30 days of the
sale, trade, or other agreement, including the identity of the recipient
of the data and information; or
(d) For license agreements, a permittee or third party that licenses
data and information to a third party must, within 30 days of a request
by the Regional Director, advise the Regional Director, in writing, of
the license agreement, including the identity of the recipient of the
data and information.

Geophysical Data and Information

Sec. 580.50 When do I notify BOEM that geophysical data and information
are available for submission, inspection, and selection?

(a) You must notify the Regional Director in writing when you
complete the initial processing and interpretation of any geophysical
data and information. Initial processing is the stage of processing
where the data and information become available for in-house
interpretation by the permittee, or become available commercially to
third parties via sale, trade, license agreement, or other means.
(b) The Regional Director may ask whether you have further processed
or interpreted any geophysical data and information. When asked, you
must respond to us in writing within 30 days.
(c) The Regional Director may request that the permittee or third
party submit geophysical data and information before making a final
selection for retention. Our representatives may inspect and select the
data and information on your premises, or the Regional Director can
request delivery of the data and information to the appropriate regional
office for review.
(d) You must submit the geophysical data and information within 30
days of receiving the request, unless the Regional Director extends the
delivery time.
(e) At any time before final selection, the Regional Director may
review and return any or all geophysical data and information. We will
notify you in writing of any data the RD decides to retain.

Sec. 580.51 What types of geophysical data and information
must I submit to BOEM?

Unless the Regional Director specifies otherwise, you must include:
(a) An accurate and complete record of each geophysical survey
conducted under the permit, including digital navigational data and
final location maps;
(b) All seismic data collected under a permit presented in a format
and of a quality suitable for processing;
(c) Processed geophysical information derived from seismic data with
extraneous signals and interference removed, presented in a quality
format suitable for interpretive evaluation, reflecting state-of-the-art
processing techniques; and
(d) Other geophysical data, processed geophysical information, and
interpreted geophysical information including, but not limited to,
shallow and deep subbottom profiles, bathymetry, sidescan sonar, gravity
and magnetic surveys, and special studies such as refraction and
velocity surveys.

Sec. 580.52 When geophysical data and information are obtained
by a third party, what must we both do?

A third party may obtain geophysical data, processed geophysical
information, or interpreted geophysical information from a permittee, or
from another third party, by sale, trade, license agreement, or other
means. If this happens:
(a) The third-party recipient of the data and information assumes
the obligations under this part, except for the notification provisions
of Sec. 580.50(a) and is subject to the penalty provisions of Sec.
580.32(a)(1) and 30 CFR 550, subpart N; and
(b) A permittee or third party that sells, trades, licenses, or
otherwise provides data and information to a third party must advise the
recipient, in writing, that accepting these obligations is a condition
precedent of the sale, trade, license, or other agreement; and
(c) Except for license agreements, a permittee or third party that
sells,

[[Page 507]]

trades, or otherwise provides data and information to a third party must
advise the Regional Director, in writing within 30 days of the sale,
trade, or other agreements, including the identity of the recipient of
the data and information; or
(d) For license agreements, a permittee or third party that licenses
data and information to a third party must, within 30 days of a request
by the Regional Director, advise the Regional Director, in writing, of
the license agreement, including the identity of the recipient of the
data and information.

Reimbursement

Sec. 580.60 Which of my costs will be reimbursed?

(a) We will reimburse you or a third party for reasonable costs of
reproducing data and information that the Regional Director requests if:
(1) You deliver G&G data and information to us for the Regional
Director to inspect or select and retain (according to Sec. Sec. 580.40
and 580.50);
(2) We receive your request for reimbursement and the Regional
Director determines that the requested reimbursement is proper; and
(3) The cost is at your lowest rate (or a third party's) or at the
lowest commercial rate established in the area, whichever is less.
(b) We will reimburse you or the third party for the reasonable
costs of processing geophysical information (which does not include cost
of data acquisition) if, at the request of the Regional Director, you
processed the geophysical data or information in a form or manner other
than that used in the normal conduct of business.

Sec. 580.61 Which of my costs will not be reimbursed?

(a) When you request reimbursement, you must identify reproduction
and processing costs separately from acquisition costs.
(b) We will not reimburse you or a third party for data acquisition
costs or for the costs of analyzing or processing geological information
or interpreting geological or geophysical information.

Protections

Sec. 580.70 What data and information will be protected
from public disclosure?

In making data and information available to the public, the Regional
Director will follow the applicable requirements of:
(a) The Freedom of Information Act (5 U.S.C. 552);
(b) The implementing regulations at 43 CFR part 2;
(c) The Act; and
(d) The regulations at 30 CFR parts 550 and 552.
(1) If the RD determines that any data or information is exempt from
disclosure under the Freedom of Information Act, we will not disclose
the data and information unless either:
(i) You and all third parties agree to the disclosure; or
(ii) A provision of 30 CFR parts 550 and 552 allows us to make the
disclosure.
(2) We will keep confidential the identity of third-party recipients
of data and information collected under a permit. We will not release
the identity unless you and the third parties agree to the disclosure.
(3) When you detect any significant hydrocarbon occurrences or
environmental hazards on unleased lands during drilling operations, the
Regional Director will immediately issue a public announcement. The
announcement must further the National interest without unduly damaging
your competitive position.

Sec. 580.71 What is the timetable for release of data and information?

We will release data and information that you or a third party
submits and we retain according to paragraphs (a) and (b) of this
section.
(a) If the data and information are not related to a deep
stratigraphic test, we will release them to the public according to
items (1), (2), and (3) in the following table:

[[Page 508]]

------------------------------------------------------------------------
The Regional Director will
If you or a third party submits and we disclose them to the public
retain . . . . . .
------------------------------------------------------------------------
(1) Geological data and information, 10 years after issuing the
permit.
(2) Geophysical data, 50 years after you or a
third party submit the
data.
(3) Geophysical information, 25 years after you or a
third party submit the
information.
(4) Data and information related to a deep 25 years after you complete
stratigraphic test, the test, unless the
provisions of paragraph (b)
of this section apply.
------------------------------------------------------------------------

(b) This paragraph applies if you are covered by paragraph (a)(4) of
this section and a lease sale is held or a noncompetitive agreement is
negotiated after you complete a test well. We will release the data and
information related to the deep stratigraphic test at the earlier of the
following times:
(1) Twenty-five years after you complete the test; or
(2) Sixty calendar days after we issue a lease, located partly or
totally within 50 geographic miles (92.7 kilometers) of the test.

Sec. 580.72 What procedure will BOEM follow to disclose acquired data
and information to a contractor for reproduction, processing,
and interpretation?

(a) When practical, the Regional Director will advise the person who
submitted data and information under Sec. 580.40 or Sec. 580.50 of the
intent to provide the data or information to an independent contractor
or agent for reproduction, processing, and interpretation.
(b) The person notified will have at least five working days to
comment on the action.
(c) When the Regional Director advises the person who submitted the
data and information, all other owners of the data or information will
be considered to have been notified.
(d) The independent contractor or agent must sign a written
commitment not to sell, trade, license, or disclose data or information
to anyone without the Regional Director's consent.

Sec. 580.73 Will BOEM share data and information with coastal States?

(a) We can disclose proprietary data, information, and samples
submitted to us by permittees or third parties that we receive under
this part to the Governor of any adjacent State that requests it
according to paragraphs (b), (c), and (d) of this section. The permittee
or third parties who submitted proprietary data, information, and
samples will be notified about the disclosure and will have at least
five working days to comment on the action.
(b) We will make a disclosure under this section only after the
Governor and the Secretary have entered into an agreement containing all
of the following provisions:
(1) The confidentiality of the information will be maintained.
(2) In any action taken for failure to protect the confidentiality
of proprietary information, neither the Federal Government nor the State
may raise as a defense:
(i) Any claim of sovereign immunity; or
(ii) Any claim that the employee who revealed the proprietary
information was acting outside the scope of his/her employment in
revealing the information.
(3) The State agrees to hold the Federal Government harmless for any
violation by the State or its employees or contractors of the agreement
to protect the confidentiality of proprietary data and information and
samples.
(4) The materials containing the proprietary data, information, and
samples will remain the property of the Federal Government.
(c) The data, information, and samples available for reproduction to
the State(s) under an agreement must be related to leased lands. Data
and information on unleased lands may be viewed but not copied or
reproduced.
(d) The State must return to us the materials containing the
proprietary data, information, and samples when we ask for them or when
the State no longer needs them.
(e) Information received and knowledge gained by a State official
under paragraph (d) of this section is subject to confidentiality
requirements of:
(1) The Act; and

[[Page 509]]

(2) The regulations at 30 CFR parts 580, 581, and 582.

Subpart E_Information Collection

Sec. 580.80 Paperwork Reduction Act statement--information collection.

(a) The Office of Management and Budget (OMB) has approved the
information collection requirements in this part under 44 U.S.C. 3501 et
seq. and assigned OMB control number 1010-0072. The title of this
information collection is ``30 CFR part 580, Prospecting for Minerals
other than Oil, Gas, and Sulphur on the Outer Continental Shelf.''
(b) We may not conduct or sponsor, and you are not required to
respond to, a collection of information unless it displays a currently
valid OMB control number.
(c) We use the information collected under this part to:
(1) Evaluate permit applications and monitor scientific research
activities for environmental and safety reasons.
(2) Determine that prospecting does not harm resources, result in
pollution, create hazardous or unsafe conditions, or interfere with
other users in the area.
(3) Approve reimbursement of certain expenses.
(4) Monitor the progress and activities carried out under an OCS
prospecting permit.
(5) Inspect and select G&G data and information collected under an
OCS prospecting permit.
(d) Respondents are Federal OCS permittees and notice filers.
Responses are mandatory or are required to obtain or retain a benefit.
We will protect information considered proprietary under applicable law
and under regulations at Sec. 580.70 and 30 CFR part 581.
(e) Send comments regarding any aspect of the collection of
information under this part, including suggestions for reducing the
burden, to the Information Collection Clearance Officer, Bureau of Ocean
Energy Management, 45600 Woodland Road, Sterling, VA 20166.

[76 FR 64623, Oct. 18, 2011, as amended at 80 FR 57098, Sept. 22, 2015]

PART 581_LEASING OF MINERALS OTHER THAN OIL, GAS, AND SULPHUR
IN THE OUTER CONTINENTAL SHELF--Table of Contents

Subpart A_General

Sec.
581.0 Authority for information collection.
581.1 Purpose and applicability.
581.2 Authority.
581.3 Definitions.
581.4 Qualifications of lessees.
581.5 False statements.
581.6 Appeals.
581.7 Disclosure of information to the public.
581.8 Rights to minerals.
581.9 Jurisdictional controversies.

Subpart B_Leasing Procedures

581.11 Unsolicited request for a lease sale.
581.12 Request for OCS mineral information and interest.
581.13 Joint State/Federal coordination.
581.14 OCS mining area identification.
581.15 Tract size.
581.16 Proposed leasing notice.
581.17 Leasing notice.
581.18 Bidding system.
581.19 Lease term.
581.20 Submission of bids.
581.21 Award of leases.
581.22 Lease form.
581.23 Effective date of leases.

Subpart C_Financial Considerations

581.26 Payments.
581.27 Annual rental.
581.28 Royalty.
581.29 Royalty valuation.
581.30 Minimum royalty.
581.31 Overriding royalties.
581.32 Waiver, suspension, or reduction of rental, minimum royalty, or
production royalty.
581.33 Bonds and bonding requirements.

Subpart D_Assignments and Lease Extensions

581.40 Assignment of leases or interests therein.
581.41 Requirements for filing for transfers.
581.42 Effect of assignment on particular lease.
581.43 Effect of suspensions on lease term.

Subpart E_Termination of Leases

581.46 Relinquishment of leases or parts of leases.
581.47 Cancellation of leases.

[[Page 510]]

Source: 76 FR 64623, Oct. 18, 2011, unless otherwise noted.

Subpart A_General

Sec. 581.0 Authority for information collection.

The information collection requirements contained in part 581 have
been approved by the Office of Management and Budget under 44 U.S.C.
3507 and assigned clearance number 1010-0082. The information is being
collected to determine if the applicant for a lease on the Outer
Continental Shelf (OCS) is qualified to hold such a lease or to
determine if a requested action is warranted. The information will be
used to make those determinations. An applicant must respond to obtain
or retain a benefit.

Sec. 581.1 Purpose and applicability.

The purpose of these regulations is to establish procedures under
which the Secretary of the Interior (Secretary) will exercise the
authority granted to administer a leasing program for minerals other
than oil, gas, and sulphur in the OCS. The rules in this part apply
exclusively to leasing activities for minerals other than oil, gas, and
sulphur in the OCS pursuant to the Act.

Sec. 581.2 Authority.

The Act authorizes the Secretary to grant leases for any mineral
other than oil, gas, and sulphur in any area of the OCS to the qualified
persons offering the highest cash bonuses on the basis of competitive
bidding upon such royalty, rental, and other terms and conditions as the
Secretary may prescribe at the time of offering the area for lease (43
U.S.C. 1337(k)). The Secretary is to administer the leasing provisions
of the Act and prescribe the rules and regulations necessary to carry
out those provisions (43 U.S.C. 1334(a)).

Sec. 581.3 Definitions.

[[Page 511]]

Outer Continental Shelf means all submerged lands lying seaward and
outside of the area of lands beneath navigable waters as defined in
section 2 of the Submerged Lands Act (43 U.S.C. 1301) and of which the
subsoil and seabed appertain to the United States and are subject to its
jurisdiction and control.
Overriding royalty means a royalty created out of the lessee's
interest which is over and above the royalty reserved to the lessor in
the original lease.
Person means a citizen or national of the United States; an alien
lawfully admitted for permanent residency in the United States as
defined in 8 U.S.C. 1101(a)(20); a private, public, or municipal
corporation organized under the laws of the United States or of any
State or territory thereof; an association of such citizens, nationals,
resident aliens or private, public, or municipal corporations, States,
or political subdivisions of States; or anyone operating in a manner
provided for by treaty or other applicable international agreements. The
term does not include Federal Agencies.
Secretary means the Secretary of the Interior or an official
authorized to act on the Secretary's behalf.

Sec. 581.4 Qualifications of lessees.

(a) In accordance with section 8(k) of the Act, leases shall be
awarded only to qualified persons offering the highest cash bonus bid.
(b) Mineral leases issued pursuant to section 8 of the Act may be
held only by:
(1) Citizens and nationals of the United States;
(2) Aliens lawfully admitted for permanent residence in the United
States as defined in 8 U.S.C. 1101(a)(20);
(3) Private, public, or municipal corporations organized under the
laws of the United States or of any State or of the District of Columbia
or territory thereof; or
(4) Associations of such citizens, nationals, resident aliens, or
private, public, or municipal corporations, States, or political
subdivisions of States.

Sec. 581.5 False statements.

Under the provisions of 18 U.S.C. 1001, it is a crime punishable by
up to 5 years imprisonment or a fine of $10,000, or both, for anyone
knowingly and willfully to submit or cause to be submitted to any Agency
of the United States any false or fraudulent statement(s) to any matters
within the Agency's jurisdiction.

Sec. 581.6 Appeals.

Any party adversely affected by a decision of a BOEM official made
pursuant to the provisions of this part shall have the right of appeal
pursuant to 30 CFR part 590, except as provided otherwise in Sec.
581.21 of this part.

Sec. 581.7 Disclosure of information to the public.

The Secretary shall make data and information available to the
public in accordance with the requirements and subject to the
limitations of the Act, the Freedom of Information Act (5 U.S.C. 552),
and the implementing regulations (30 CFR parts 580, 582, and 43 CFR part
2).

Sec. 581.8 Rights to minerals.

(a) Unless otherwise specified in the leasing notice, a lease for
OCS minerals shall include rights to all minerals within the leased area
except the following;
(1) Minerals subject to rights granted by existing leases;
(2) Oil;
(3) Gas;
(4) Sulphur;
(5) Minerals produced in direct association with oil, gas, or
sulphur;
(6) Salt deposits which are identified in the leasing notice as
being reserved;
(7) Sand and gravel deposits which are identified in the leasing
notice as being reserved; and
(8) Source materials essential to production of fissionable
materials which are reserved pursuant to section 12(a) of the Act.
(b) When an OCS mineral lease issued under this part limits the
minerals to which rights are granted, such lease shall include rights to
minerals produced in direct association with the OCS mineral specified
in the lease but

[[Page 512]]

not the rights to minerals specifically reserved.
(c) The existence of an OCS mineral, oil and gas, or sulphur lease
shall not preclude the issuance of a lease(s) for other OCS minerals in
the same area. However, no OCS mineral lease shall authorize or permit
the lessee thereunder to unreasonably interfere with or endanger
operations under an existing OCS mineral, oil and gas, or sulphur lease.

Sec. 581.9 Jurisdictional controversies.

In the event of a controversy between the United States and a State
as to whether certain lands are subject to Federal or State jurisdiction
(43 U.S.C. 1336), either the Governor or the Secretary may initiate
negotiations in an attempt to settle the jurisdictional controversy.
With the concurrence of the Attorney General, the Secretary may enter
into an agreement with a State with respect to OCS mineral activities
under the Act or under State authority and to payment and impounding of
rents, royalties, and other sums and with respect to the offering of
lands for lease pending settlement of the controversy.

Subpart B_Leasing Procedures

Sec. 581.11 Unsolicited request for a lease sale.

(a) Any person may at any time request that OCS minerals be offered
for lease. A request that OCS minerals be offered for lease shall be
submitted to the Director and shall contain the following information:
(1) The area to be offered for lease.
(2) The OCS minerals of primary interest.
(3) The available OCS mineral resource and environmental information
pertaining to the area of interest to be offered for lease which
supports the request.
(b) Within 45 days after receipt of a request submitted under
paragraph (a) of this section, the Director shall either initiate steps
leading to the offer of OCS minerals for lease and notify the applicant
of the action taken or inform the applicant of the reasons for not
initiating steps leading to the offer of OCS minerals for lease.
(c) Any interested party may at any time submit information to the
Director concerning the scheduling of proposed lease sales of OCS
minerals in any area of the OCS. Such information may include but not be
limited to any of the following:
(1) Benefits of conducting a lease sale in an area.
(2) Costs of conducting a lease sale in an area.
(3) Geohazards which could be encountered in an area.
(4) Geological information about an area and mineral resource
potential.
(5) Environmental information about an area.
(6) Information about known archaeological resources in an area.

Sec. 581.12 Request for OCS mineral information and interest.

(a) When considering whether to offer OCS minerals for lease, the
Secretary, upon the Department of the Interior's own initiative or as a
result of a submission under Sec. 581.11, may request indications of
interest in the leasing of a specific OCS mineral, a group of OCS
minerals, or all OCS minerals in the area being considered for lease.
Requests for information and interest shall be published in the Federal
Register and may be published elsewhere.
(b) States and local governments, industry, other Federal Agencies,
and all interested parties (including the public) may respond to a
request for information and interest. All information provided to the
Secretary will be considered in the decision whether to proceed with
additional steps leading to the offering of OCS minerals for lease.
(c) The Secretary may request specific information concerning the
offering of a specific OCS mineral, a group of OCS minerals, or all OCS
minerals in a broad area for lease or the offering of one or more
discrete tracts which represent a minable orebody. The Secretary's
request may ask for comments on OCS areas which have been determined to
warrant special consideration and analysis. Requests may be for comments
concerning geological conditions or archaeological resources on the
seabed; multiple uses of the area proposed for leasing, including
navigation,

[[Page 513]]

recreation and fisheries; and other socioeconomic, biological, and
environmental information relating to the area proposed for leasing.

Sec. 581.13 Joint State/Federal coordination.

(a) The Secretary may invite the adjacent State Governor(s) to join
in, or the adjacent State Governor(s) may request that the Secretary
join in, the establishment of a State/Federal task force or some other
joint planning or coordination arrangement when industry interest exists
for OCS mineral leasing or geological information appears to support the
leasing of OCS minerals in specific areas. Participation in joint State/
Federal task forces or other arrangements will afford the adjacent State
Governor(s) opportunity for access to available data and information
about the area; knowledge of progress made in the leasing process and of
the results of subsequent exploration and development activities;
facilitate the resolution of issues of mutual interest; and provide a
mechanism for planning, coordination, consultation, and other activities
which the Secretary and the Governor(s) may identify as contributing to
the leasing process.
(b) State/Federal task forces or other such arrangements are to be
constituted pursuant to such terms and conditions (consistent with
Federal law and these regulations) as the Secretary and the adjacent
State Governor(s) may agree.
(c) State/Federal task forces or other such arrangements will
provide a forum which the Secretary and adjacent State Governor(s) may
use for planning, consultation, and coordination on concerns associated
with the offering of OCS minerals other than oil, gas, or sulphur for
lease.
(d) With respect to the activities authorized under these
regulations each State/Federal task force may make recommendations to
the Secretary and adjacent State Governor(s) concerning:
(1) The identification of areas in which OCS minerals might be
offered for lease;
(2) The potential for conflicts between the exploration and
development of OCS mineral resources, other users and uses of the area,
and means for resolution or mitigation of these conflicts;
(3) The economic feasibility of developing OCS mineral resources in
the area proposed for leasing;
(4) Potential environmental problems and measures that might be
taken to mitigate these problems;
(5) Development of guidelines and procedures for safe,
environmentally responsible exploration and development practices; and
(6) Other issues of concern to the Secretary and adjacent State
Governor(s).
(e) State/Federal task forces or other such arrangements might also
be used to conduct or oversee research, studies, or reports (e.g.,
Environmental Impact Statements).

Sec. 581.14 OCS mining area identification.

The Secretary, after considering the available OCS mineral resources
and environmental data and information, the recommendation of any joint
State/Federal task force established pursuant to Sec. 581.13 of this
part, and the comments received from interested parties, shall select
the tracts to be considered for offering for lease. The selected tracts
will be considered in the environmental analysis conducted for the
proposed lease offering.

Sec. 581.15 Tract size.

The size of the tracts to be offered for lease shall be as
determined by the Secretary and specified in the leasing notice. It is
intended that tracts offered for lease be sufficiently large to include
potentially minable OCS mineral orebodies. When the presence of any
minable orebody is unknown and additional prospecting is needed to
discover and delineate OCS minerals, the size of tracts specified in the
leasing notice may be relatively large.

Sec. 581.16 Proposed leasing notice.

(a) Prior to offering OCS minerals in an area for lease, the
Director shall assess the available information including
recommendations of any joint State/Federal task force established

[[Page 514]]

pursuant to Sec. 581.13 of this part to determine lease sale procedures
to be prescribed and to develop a proposed leasing notice which sets out
the proposed primary term of the OCS mineral leases to be offered; lease
stipulations including measures to mitigate potentially adverse impacts
on the environment; and such rental, royalty, and other terms and
conditions as the Secretary may prescribe in the leasing notice.
(b) The proposed leasing notice shall be sent to the Governor(s) of
any adjacent State(s), and a Notice of its availability shall be
published in the Federal Register at least 60 days prior to the
publication of the leasing notice.
(c) Written comments of the adjacent State Governor(s) submitted
within 60 days after publication of the Notice of Availability of the
proposed leasing notice shall be considered by the Secretary.
(d) Prior to publication of the leasing notice, the Secretary shall
respond in writing to the comments of the adjacent State Governor(s)
stating the reasons for accepting or rejecting the Governor's
recommendations, or for implementing any alternative mutually acceptable
approach identified in consultation with the Governor(s) as a means to
provide a reasonable balance between the National interest and the well
being of the citizens of the adjacent State.

Sec. 581.17 Leasing notice.

(a) The Director shall publish the leasing notice in the Federal
Register at least 30 days prior to the date that OCS minerals will be
offered for lease. The leasing notice shall state whether oral or sealed
bids or a combination thereof will be used; the place, date, and time at
which sealed bids shall be filed; and the place, date, and time at which
sealed bids shall be opened and/or oral bids received. The leasing
notice shall contain or reference a description of the tract(s) to be
offered for lease; specify the mineral(s) to be offered for lease (if
less than all OCS minerals are being offered); specify the period of
time the primary term of the lease shall cover; and any stipulation(s),
term(s), and condition(s) of the offer to lease (43 U.S.C. 1337(k)).
(b) The leasing notice shall contain a reference to the OCS minerals
lease form which shall be issued to successful bidders.
(c) The leasing notice shall specify the terms and conditions
governing the payment of the winning bid.

Sec. 581.18 Bidding system.

(a) The OCS minerals shall be offered by competitive, cash bonus
bidding under terms and conditions specified in the leasing notice and
in accordance with all applicable laws and regulations.
(b)(1) When the leasing notice specifies the use of sealed bids,
such bids received in response to the leasing notice shall be opened at
the place, date, and time specified in the leasing notice. The sole
purpose of opening bids is to publicly announce and record the bids
received, and no bids shall be accepted or rejected at that time.
(2) The Secretary reserves the right to reject any and all sealed
bids received for any tract, regardless of the amount offered.
(3) In the event the highest bids are tie bids when using sealed
bidding procedures, the tied bidders may be permitted to submit oral
bids to determine the highest cash bonus bidder.
(c)(1) When the leasing notice specifies the use of oral bids, oral
bids shall be received at the place, time, and date and in accordance
with the procedures specified in the leasing notice.
(2) The Secretary reserves the right to reject all oral bids
received for any tract, regardless of the amount offered.
(d) When the leasing notice specifies the use of deferred cash bonus
bidding, bids shall be received in accordance with paragraph (b) or (c)
of this section, as appropriate. The high bid will be determined based
upon the net present value of each total bid. The appropriate discount
rate will be specified in the leasing notice. High bidders using the
deferred bonus option shall pay a minimum of 20 percent of the cash
bonus bid prior to lease issuance. At least a total of 60 percent of the
cash bonus bid shall be due on or before the 5th anniversary of the
lease, and payment of the remainder of the cash

[[Page 515]]

bonus bid shall be due on the 10th anniversary of the lease. The lessee
shall submit a bond guaranteeing payment of the deferred portion of the
bonus, in accordance with Sec. 581.33.

Sec. 581.19 Lease term.

An OCS mineral lease for OCS minerals other than sand and gravel
shall be for a primary term of not less than 20 years as stipulated in
the leasing notice. The primary lease term for each OCS mineral shall be
determined based on exploration and development requirements for the OCS
minerals being offered by the Secretary. An OCS mineral lease for sand
and gravel shall be for a primary term of 10 years unless otherwise
stipulated in the leasing notice. A lease will continue beyond the
specified primary term for so long thereafter as leased OCS minerals are
being produced in accordance with an approved mining operation or the
lessee is otherwise in compliance with provisions of the lease and the
regulations in this chapter under which a lessee can earn continuance of
the OCS mineral lease in effect.

Sec. 581.20 Submission of bids.

(a) If the bidder is an individual, a statement of citizenship shall
accompany the bid.
(b) If the bidder is an association (including a partnership), the
bid shall be accompanied by a certified statement indicating the State
in which it is registered and that the association is authorized to hold
mineral leases on the OCS, or appropriate reference to statements or
records previously submitted to a BOEM OCS office (including material
submitted in compliance with prior regulations).
(c) If the bidder is a corporation, the bid shall be accompanied by
the following information:
(1) Either a statement certified by the corporate Secretary or
Assistant Secretary over the corporate seal showing the State in which
it was incorporated and that it is authorized to hold mineral leases on
the OCS or appropriate reference to statements or record previously
submitted to a BOEM OCS office (including material submitted in
compliance with prior regulations).
(2) Evidence of authority of persons signing to bind the
corporation. Such evidence may be in the form of a certified copy of
either the minutes of the board of directors or of the bylaws indicating
that the person signing has authority to do so, or a certificate to that
effect signed by the Secretary or Assistant Secretary of the corporation
over the corporate seal, or appropriate reference to statements or
records previously submitted to a BOEM OCS office (including material
submitted in compliance with prior regulations). Bidders are advised to
keep their filings current.
(3) The bid shall be executed in conformance with corporate
requirements.
(d) Bidders should be aware of the provisions of 18 U.S.C. 1860,
which prohibits unlawful combination or intimidation of bidders.
(e) When sealed bidding is specified in the leasing notice, a
separate sealed bid shall be submitted for each bid unit that is bid
upon as described in the leasing notice. A bid may not be submitted for
less than a bidding unit identified in the leasing notice.
(f) When oral bidding is specified in the leasing notice,
information which must accompany a bid pursuant to paragraph (a), (b),
or (c) of this section, shall be presented to BOEM at the lease sale
prior to the offering of an oral bid.

Sec. 581.21 Award of leases.

(a)(1) The decision of the Director on bids shall be the final
action of the Department, subject only to reconsideration by the
Secretary, pursuant to a written request in accordance with paragraph
(a)(2) of this section. The delegation of review authority to the Office
of Hearings and Appeals shall not be applicable to decisions on high
bids for leases in the OCS.
(2) Any bidder whose bid is rejected by the Director may file a
written request for reconsideration with the Secretary within 15 days of
notice of rejection, accompanied by a statement of reasons with a copy
to the Director. The Secretary shall respond in writing either affirming
or reversing the decision.
(b) Written notice of the Director's action in accepting or
rejecting bids

[[Page 516]]

shall be transmitted promptly to those bidders whose deposits have been
held. If a bid is accepted, such notice shall transmit three copies of
the lease form to the successful bidder. As provided in Sec. 581.26 of
this part, the bidder shall, not later than the 10th business day after
receipt of the lease, execute the lease, pay the first year's rental,
and unless payment of a portion of the bid is deferred, pay the balance
of the bonus bid. When payment of a portion of the bid is deferred, the
successful bidder shall also file a bond to guarantee payment of the
deferred portion as required in Sec. 581.33. Deposits shall be refunded
on high bids subsequently rejected. When three copies of the lease have
been executed by the successful bidder and returned to the Director, the
lease shall be executed on behalf of the United States; and one fully
executed copy shall be transmitted to the successful bidder.
(c) If the successful bidder fails to execute the lease within the
prescribed time or to otherwise comply with the applicable regulations,
the successful bidder's deposit shall be forfeited and disposed of in
the same manner as other receipts under the Act.
(d) If, before the lease is executed on behalf of the United States,
the land which would be subject to the lease is withdrawn or restricted
from leasing, the deposit shall be refunded.
(e) If the awarded lease is executed by an agent acting on behalf of
the bidder, the bidder shall submit with the executed lease, evidence
that the agent is authorized to act on behalf of the bidder.

Sec. 581.22 Lease form.

The OCS mineral leases shall be issued on the lease form prescribed
by the Secretary in the leasing notice.

Sec. 581.23 Effective date of leases.

Leases issued under the regulations in this part shall be dated and
become effective as of the first day of the month following the date
leases are signed on behalf of the lessor except that, upon written
request, a lease may be dated and become effective as of the first day
of the month within which it is signed on behalf of the lessor.

Subpart C_Financial Considerations

Sec. 581.26 Payments.

(a) For sealed bids, a bonus bid deposit of a specified percentage
of the total amount bid is required to be submitted with the bid. The
percentage of bonus bid required to be deposited will be specified in
the leasing notice. The remittance may be made in cash or by Federal
Reserve check, commercial check, bank draft, money order, certified
check, or cashier's check made payable to ``Department of the Interior--
BOEM.'' Payment of this portion of the bonus bid may not be made by
Electronic Funds Transfer.
(b) For oral bids, a bonus bid deposit of a specified percentage of
the total amount bid must be submitted to the official designated in the
leasing notice following the completion of the oral bidding. The
percentage of bonus bid required to be deposited will be specified in
the leasing notice. Payment of this portion of the bonus bid must be
made by Electronic Fund Transfer within the timeframe specified in the
leasing notice.
(c) The deposit received from high bidders will be placed in a
Treasury account pending acceptance or rejection of the bid. Other bids
submitted under paragraph (a) of this section will be returned to the
bidders. If the high bid is subsequently rejected, an amount equal to
that deposited with the high bid will be returned according to
applicable regulations.
(d) The balance of the winning bonus bid and all rentals and
royalties must be paid in accordance with the terms and conditions of
this part, the Leasing Notice, and subchapter A of this chapter.
(e) For each lease issued pursuant to this subpart, there shall be
one person identified who shall be solely responsible for all payments
due and payable under the provisions of the lease. The single
responsible person shall be designated as the payor for the lease and
shall be so identified on the Solid Minerals Production and Royalty
Report (P&R) (Form ONRR-4430) in accordance with 30 CFR 1210.201 of this
title. The designated person shall be responsible

[[Page 517]]

for all bonus, rental, and royalty payments.
(f) Royalty shall be computed at the rate specified in the leasing
notice, and paid in value unless the Secretary elects to have the
royalty delivered in kind.
(g) For leases which provide for minimum royalty payments, each
lessee shall pay the minimum royalty specified in the lease at the end
of each lease year beginning with the lease year in which production
royalty is paid (whether the full amount specified in the lease or \1/2\
the amount specified in the lease pursuant to Sec. 581.28(b) on this
part) of OCS minerals produced (sold, transferred, used, or otherwise
disposed of) from the leasehold.
(h)(1) Unless stated otherwise in the lease, product valuation will
be in accordance with the regulations in part 1206 of chapter XII. The
value used in the computation of royalty shall be determined by the
Director of the Office of Natural Resources Revenue. The value, for
royalty purposes, shall be the gross proceeds received by the lessee for
produced substances at the point the product is produced and placed in
its first marketable condition, consistent with prevailing practices in
the industry. In establishing the value, the Director shall consider, in
this order:
(i) The price received by the lessee;
(ii) Commodity and spot market transactions;
(iii) Any other valuation method proposed by the lessee and approved
by the Director; and
(iv) Value or cost netback.
(2) For non-arm's length transactions, the first benchmark will only
be accepted if it is not less than the second benchmark.
(i) All payors must submit payments and payment forms and maintain
auditable records in accordance with 30 CFR chapter XII, Subchapter A--
Natural Resources Revenue.

Sec. 581.27 Annual rental.

(a) The annual lease rental shall be due and payable in accordance
with the provisions of this section. No rental shall be due or payable
under a lease commencing with the first lease anniversary date following
the commencement of royalty payments on leasehold production computed on
the basis of the royalty rate specified in the lease except that annual
rental shall be due for any year in which production from the leasehold
is not subject to royalty pursuant to Sec. 581.28.
(b) Unless otherwise specified in the leasing notice and
subsequently issued lease, no annual rental payment shall be due during
the first 5 years in the life of a lease.
(c) The leasee shall pay an annual rental in the amount specified in
the leasing notice and subsequently issued lease not later than the last
day prior to the commencement of the rental year.
(d) A rental adjustment schedule and amount may be specified in a
leasing notice and subsequently issued lease when a variance is
warranted by geologic, geographic, technical, or economic conditions.

Sec. 581.28 Royalty.

(a) The royalty due the lessor on OCS minerals produced (i.e., sold,
transferred, used, or otherwise disposed of) from a lease shall be set
out in a separate schedule attached to and made a part of each lease and
shall be as specified in the leasing notice. The royalty due on
production shall be based on a percentage of the value or amount of the
OCS mineral(s) produced, a sum assessed per unit of product, or other
such method as the Secretary may prescribe in the leasing notice. When
the royalty specified is a sum assessed per unit of product, the amount
of the royalty shall be subject to an annual adjustment based on changes
in the appropriate price index, when specified in the leasing notice.
When the royalty is specified as a percentage of the value or amount of
the OCS minerals produced, the Secretary will notify the lessee when and
where royalty is to be delivered in kind. Unless stated otherwise in the
lease, product valuation will be in accordance with the regulations in
part 1206 of chapter XII. The value used in the computation of royalty
shall be determined by the Director of the Office of Natural Resources
Revenue.

[[Page 518]]

(b) When prescribed in the leasing notice and subsequently issued
lease, royalty due on OCS minerals produced from a leasehold will be
reduced for up to any 5 consecutive years, as specified by the lessee
prior to the commencement of production, during the 1st through 15th
year in the life of the lease. No royalty shall be due in any year of
the specified 5-year period that occurs during the 1st through 10th
years in the life of the lease, and a royalty of one-half the amount
specified in the lease shall be due in any year of the specified 5-year
period that occurs in the 11th through 15th year in the life of the
lease. The lessee shall pay the amount specified in the lease rental for
any royalty free year. The minimum royalty specified in the lease shall
apply during any year of reduced royalty.

Sec. 581.29 Royalty valuation.

Unless stated otherwise in the leasing notice and subsequently
issued lease, product valuation will be in accordance with the
regulations in part 1206 of chapter XII. The value used in the
computation of royalty shall be determined by the Director of the Office
of Natural Resources Revenue.

Sec. 581.30 Minimum royalty.

Unless otherwise specified in the leasing notice, each lease issued
pursuant to the regulations in this part shall require the payment of a
specified minimum annual royalty beginning with the year in which OCS
minerals are produced (sold, transferred, used, or otherwise disposed
of) from the leasehold except that the annual rentals shall apply during
any year that royalty free production is in effect pursuant to Sec.
581.28(b). Minimum royalty payments shall be offset by royalty paid on
production during the lease year. Minimum royalty payments are due at
the beginning of the lease year and payable by the end of the month
following the end of the lease year for which they are due.

Sec. 581.31 Overriding royalties.

(a) Subject to the approval of the Secretary, an overriding royalty
interest may be created by an assignment pursuant to section 8(e) of the
Act. The Secretary may deny approval of an assignment which creates an
overriding royalty on a lease whenever that denial is determined to be
in the interest of conservation, necessary to prevent premature
abandonment of a producing mine, or to make possible the mining of
economically marginal or low-grade ore deposits. In any case, the total
of applicable overriding royalties may not exceed 2.5 percent or one-
half the base royalty due the Federal Government, whichever is less.
(b) No transfer or agreement may be made which creates an overriding
royalty interest unless the owner of that interest files an agreement in
writing that such interest is subject to the limitations provided in
Sec. 581.30 of this part, paragraph (a) of this section, and Sec.
581.32 of this part.

Sec. 581.32 Waiver, suspension, or reduction of rental, minimum royalty,
or production royalty.

(a) The Secretary may waive, suspend, or reduce the rental, minimum
royalty, and/or production royalty prescribed in a lease for a specified
time period when the Secretary determines that it is in the National
interest, it will result in the conservation of natural resources of the
OCS, it will promote development, or the mine cannot be successfully
operated under existing conditions.
(b) An application for waiver, suspension, or reduction of rental,
minimum royalty, or production royalty under paragraph (a) of this
section shall be filed in duplicate with the Director. The application
shall contain the serial number(s) of the lease(s), the name of the
lessee(s) of record, and the operator(s) if applicable. The application
shall either:
(1)(i) Show the location and extent of all mining operations and a
tabulated statement of the minerals mined and subject to royalty for
each of the last 12 months immediately prior to filing the application:
(ii) Contain a detailed statement of expenses and costs of operating
the lease, the income from the sale of any lease products, and the
amount of all overriding royalties and payments out of production paid
to others than the United States; and

[[Page 519]]

(iii) All facts showing whether or not the mine(s) can be
successfully operated under the royalty fixed in the lease; or
(2) If no production has occurred from the lease, show that the
lease cannot be successfully operated under the rental, royalty, and
other conditions specified in the lease.
(c) The applicant for a waiver, suspension, or reduction under this
section shall file documentation that the lessee and the royalty holders
agree to a reduction of all other royalties from the lease so that the
aggregate of all other royalties does not exceed one-half the amount of
the reduced royalties that would be paid to the United States.

Sec. 581.33 Bonds and bonding requirements.

(a) When the leasing notice specifies that payment of a portion of
the bonus bid can be deferred, the lessee shall be required to submit a
surety or personal bond to guarantee payment of a deferred portion of
the bid. Upon the payment of the full amount of the cash bonus bid, the
lessee's bond will be released.
(b) All bonds to guarantee payment of the deferred portion of the
high cash bonus bid furnished by the lessee must be in a form or on a
form approved by the Deputy Director. A single copy of the required form
is to be executed by the principal or, in the case of surety bonds, by
both the principal and an acceptable surety.
(1) Only those surety bonds issued by qualified surety companies
approved by the Department of the Treasury shall be accepted (see
Department of the Treasury Circular No. 570 and any supplemental or
replacement circulars).
(2) Personal bonds shall be accompanied by a cashier's check,
certified check, or negotiable U.S. Treasury bonds of an equal value to
the amount specified in the bond. Negotiable Treasury bonds shall be
accompanied by a proper conveyance of full authority to the Director to
sell such securities in case of default in the performance of the terms
and conditions of the lease.
(c) Prior to the commencement of any activity on a lease(s), the
lessee shall submit a surety or personal bond as described in Sec.
582.40 of this title. Prior to the approval of a Delineation, Testing,
or Mining Plan, the bond amount shall be adjusted, if appropriate, to
cover the operations and activities described in the proposed plan.

[76 FR 64623, Oct. 18, 2011, as amended at 80 FR 57098, Sept. 22, 2015]

Subpart D_Assignments and Lease Extensions

Sec. 581.40 Assignment of leases or interests therein.

(a) Subject to the approval of the Secretary, a lease may be
assigned, in whole or in part, pursuant to section 8(e) of the Act to
anyone qualified to hold a lease.
(b) Any approved assignment shall be deemed to be effective on the
first day of the lease month following the date that it is submitted to
the Director for approval unless by written request the parties request
that the effective date be the first of the month in which the Director
approves the assignment.
(c) The assignor shall be liable for all obligations under the lease
occurring prior to the effective date of an assignment.
(d) The assignee shall be liable for all obligations under the lease
occurring on or after the effective date of an assignment and shall
comply with all terms and conditions of the lease and applicable
regulations issued under the Act.

Sec. 581.41 Requirements for filing for transfers.

(a)(1) All instruments of transfer of a lease or of an interest
therein including subleases and assignments of record interest shall be
filed in triplicate for approval within 90 days from the date of final
execution. They shall include a statement over the transferee's own
signature with respect to citizenship and qualifications similar to that
required of a lessee and shall contain all of the terms and conditions
agreed upon by the parties thereto.
(2) An application for approval of any instrument required to be
filed will not be accepted unless a nonrefundable fee of $50 is paid
electronically through Pay.gov at: https://www.pay.gov/paygov/ and a
copy of the Pay.gov confirmation

[[Page 520]]

receipt page is included with your application. For any document you are
not required to file by these regulations but which you submit for
record purposes, you must also pay electronically through Pay.gov a
nonrefundable fee of $50 per lease affected, and you must include a copy
of the Pay.gov confirmation receipt page with your document. Such
documents may be rejected at the discretion of the authorized officer.
(b) An attorney in fact signing on behalf of the holder of a lease
or sublease, shall furnish evidence of authority to execute the
assignment or application for approval and the statement required by
Sec. 581.20 of this part.
(c) Where an assignment creates separate leases, a bond shall be
furnished for each of the resulting leases in the amount prescribed in
Sec. 582.40 of this title. Where an assignment does not create separate
leases, the assignee, if the assignment so provides and the surety
consents, may become a joint principal on the bond with the assignor.
(d) An heir or devisee of a deceased holder of a lease or any
interest therein shall be recognized as the lawful successor to such
lease or interest if evidence of status as an heir or devisee is
furnished in the form of:
(1) A certified copy of an appropriate order or decree of the court
having jurisdiction over the distribution of the estate, or
(2) If no court action is necessary, the statement of two
disinterested persons having knowledge of the fact or a certified copy
of the will.
(e) The heirs or devisee shall file statements that they are the
persons named as successors to the estate with evidence of their
qualifications to hold such lease or interest therein.
(f) In the event an heir or devisee is unable to qualify to hold the
lease or interest, the heir or devisee shall be recognized as the lawful
successor of the deceased and be entitled to hold the lease for a period
not to exceed 2 years from the date of death of the predecessor in
interest.
(g) Each obligation under any lease and under the regulations in
this part shall inure to the heirs, executors, administrators,
successors, or assignees of the lease.

Sec. 581.42 Effect of assignment on particular lease.

(a) When an assignment is made of all the record title to a portion
of the acreage in a lease, the assigned and retained portions of the
lease area become segregated into separate and distinct leases. In such
a case, the assignee becomes a lessee of the Government as to the
segregated tract that is the subject of the assignment and is bound by
the terms of the lease as though the lease had been obtained from the
United States in the assignee's own name, and the assignment, after its
approval, shall be the basis of a new record. Royalty, minimum royalty,
and annual rental provisions of the lease shall apply separately to each
segregated portion.
(b) Each lease of an OCS mineral created by the segregation of a
lease under paragraph (a) of this section shall continue in full force
and effect for the remainder of the primary term of the original lease
and so long thereafter as minerals are produced from the portion of the
lease created by segregation in accordance with operations approved by
the Director or the lessee is otherwise in compliance with provisions of
the lease or regulations for earning the continuation of the lease in
effect.

Sec. 581.43 Effect of suspensions on lease term.

(a) If the BSEE Director orders the suspension of either operations
or production, or both, with respect to any lease in its primary term,
the primary term of the lease shall be extended by a period of time
equivalent to the period of the directed suspension.
(b) If the BSEE Director orders or approves the suspension of either
operations or production, or both, with respect to any lease that is in
force beyond its primary term, the term of the lease shall not be deemed
to expire so long as the suspension remains in effect.

[[Page 521]]

Subpart E_Termination of Leases

Sec. 581.46 Relinquishment of leases or parts of leases.

(a) A lease or any part thereof may be surrendered by the record
title holder by filing a written relinquishment with the Director. A
relinquishment shall take effect on the date it is filed subject to the
continued obligation of the lessee and the surety to:
(1) Make all payments due, including any accrued rentals and
royalties; and
(2) Abandon all operations, remove all facilities, and clear the
land to be relinquished to the satisfaction of the Director.
(b) Upon relinquishment of a lease, the data and information
submitted under the lease will no longer be held confidential and will
be available to the public.

Sec. 581.47 Cancellation of leases.

(a) Whenever the owner of a nonproducing lease fails to comply with
any of the provisions of the Act, the lease, or the regulations issued
under the Act, and the default continues for a period of 30 days after
mailing of notice by registered or certified letter to the lease owner
at the owner's record post office address, the Secretary may cancel the
lease pursuant to section 5(c) of the Act, and the lessee shall not be
entitled to compensation. Any such cancellation is subject to judicial
review as provided by section 23(b) of the Act.
(b) Whenever the owner of any producing lease fails to comply with
any of the provisions of the Act, the lease, or the regulations issued
under the Act, the Secretary may cancel the lease only after judicial
proceedings pursuant to section 5(d) of the Act, and the lessee shall
not be entitled to compensation.
(c) Any lease issued under the Act, whether producing or not, may be
canceled by the Secretary upon proof that it was obtained by fraud or
misrepresentation and after notice and opportunity to be heard has been
afforded to the lessee.
(d) The Secretary may cancel a lease in accordance with the
following:
(1) Cancellation may occur at any time if the Secretary determines
after a hearing that:
(i) Continued activity pursuant to such lease would probably cause
serious harm or damage to life (including fish and other aquatic life),
to property, to any mineral (in areas leased or not leased), to the
National security or defense, or to the marine, coastal, or human
environment;
(ii) The threat of harm or damage will not disappear or decrease to
an acceptable extent within a reasonable period of time; and
(iii) The advantages of cancellation outweigh the advantages of
continuing such lease in force;
(2) Cancellation shall not occur unless and until operations under
such lease shall have been under suspension or temporary prohibition by
the Secretary, with due extension of any lease term continuously for a
period of 5 years, or for a lesser period upon request of the lessee;
and
(3) Cancellation shall entitle the lessee to receive such
compensation as is shown to the Secretary as being equal to the lesser
of:
(i) The fair value of the canceled rights as of the date of
cancellation, taking into account both anticipated revenues from the
lease and anticipated costs, including costs of compliance with all
applicable regulations and operating orders, liability for cleanup costs
or damages, or both, and all other costs reasonably anticipated on the
lease, or
(ii) The excess, if any, over the lessee's revenues from the lease
(plus interest thereon from the date of receipt to date of
reimbursement) of all consideration paid for the lease and all direct
expenditures made by the lessee after the date of issuance of such lease
and in connection with exploration or development, or both, pursuant to
the lease (plus interest on such consideration and such expenditures
from date of payment to date of reimbursement), except that in the case
of joint leases which are canceled due to the failure of one or more
partners to exercise due diligence, the innocent parties shall have the
right to seek damages for such loss from the responsible party or
parties and the right to acquire the interests of the negligent party or
parties and be issued the lease in question.

[[Page 522]]

(iii) The lessee shall not be entitled to compensation where one of
the following circumstances exists when a lease is canceled:
(A) A producing lease is forfeited or is canceled pursuant to
section (5)(d) of the Act;
(B) A Testing Plan or Mining Plan is disapproved because of the
lessee's failure to demonstrate compliance with the requirements of
applicable Federal Law; or
(C) The lessee(s) of a nonproducing lease fails to comply with a
provision of the Act, the lease, or regulations issued under the Act,
and the noncompliance continues for a period of 30 days or more after
the mailing of a notice of noncompliance by registered or certified
letter to the lessee(s).

PART 582_OPERATIONS IN THE OUTER CONTINENTAL SHELF FOR MINERALS OTHER THAN
OIL, GAS, AND SULPHUR--Table of Contents

Subpart A_General

Sec.
582.0 Authority for information collection.
582.1 Purpose and authority.
582.2 Scope.
582.3 Definitions.
582.4 Opportunities for review and comment.
582.5 Disclosure of data and information to the public.
582.6 Disclosure of data and information to an adjacent State.
582.7 Jurisdictional controversies.

Subpart B_Jurisdiction and Responsibilities of Director

582.10 Jurisdiction and responsibilities of Director.
582.11 Director's authority.
582.12 Director's responsibilities.
582.13 [Reserved]
582.14 Noncompliance, remedies, and penalties.
582.15 Cancellation of leases.

Subpart C_Obligations and Responsibilities of Lessees

582.20 Obligations and responsibilities of lessees.
582.21 Plans, general.
582.22 Delineation Plan.
582.23 Testing Plan.
582.24 Mining Plan.
582.25 Plan modification.
582.26 Contingency Plan.
582.27 Conduct of operations.
582.28 Environmental protection measures.
582.29 Reports and records.
582.30 Right of use and easement.
582.31 [Reserved]

Subpart D_Payments

582.40 Bonds.
582.41 Method of royalty calculation.
582.42 Payments.

Subpart E_Appeals

582.50 Appeals.

Source: 76 FR 64623, Oct. 18, 2011, unless otherwise noted.

Subpart A_General

Sec. 582.0 Authority for information collection.

The information collection requirements in this part have been
approved by the Office of Management and Budget under 44 U.S.C. 3507 and
assigned clearance number 1010-0081. The information is being collected
to inform the Bureau of Ocean Energy Management (BOEM) of general mining
operations in the Outer Continental Shelf (OCS). The information will be
used to ensure that operations are conducted in a safe and
environmentally responsible manner in compliance with governing laws and
regulations. The requirement to respond is mandatory.

Sec. 582.1 Purpose and authority.

[[Page 523]]

States and other Departments and Agencies of the Federal Government.
(b) Subject to the supervisory authority of the Secretary, and
unless otherwise specified, the regulations in this part shall be
administered by the Director of BOEM.

Sec. 582.2 Scope.

Sec. 582.3 Definitions.

When used in this part, the following terms shall have the meaning
given below:
Act means the OCS Lands Act, as amended (43 U.S.C. 1331 et seq.).
Adjacent State means with respect to any activity proposed,
conducted, or approved under this part, any coastal State:
(1) That is, or is proposed to be, receiving for processing,
refining, or transshipment OCS mineral resources commercially recovered
from the seabed;
(2) That is used, or is scheduled to be used, as a support base for
prospecting, exploration, testing, or mining activities; or
(3) In which there is a reasonable probability of significant effect
on land or water uses from such activity.
Contingency Plan means a plan for action to be taken in emergency
situations.
Data means geological and geophysical (G&G) facts and statistics or
samples which have not been analyzed, processed, or interpreted.
Development means those activities which take place following the
discovery of minerals in paying quantities including geophysical
activities, drilling, construction of offshore facilities, and operation
of all onshore support facilities, which are for the purpose of
ultimately producing the minerals discovered.
Director means the Director of BOEM of the U.S. Department of the
Interior or an official authorized to act on the Director's behalf.
Exploration means the process of searching for minerals on a lease
including:
(1) Geophysical surveys where magnetic, gravity, seismic, or other
systems are used to detect or imply the presence of minerals;
(2) Any drilling including the drilling of a borehole in which the
discovery of a mineral other than oil, gas, or sulphur is made and the
drilling of any additional boreholes needed to delineate any mineral
deposits; and
(3) The taking of sample portions of a mineral deposit to enable the
lessee to determine whether to proceed with development and production.
Geological sample means a collected portion of the seabed, the
subseabed, or the overlying waters (when obtained for geochemical
analysis) acquired while conducting postlease mining activities.
Governor means the Governor of a State or the person or entity
designated by, or pursuant to, State law to exercise the power granted
to a Governor.
Information means G&G data that have been analyzed, processed, or
interpreted.
Lease means one of the following, whichever is required by the
context: Any form of authorization which is issued under section 8 or
maintained under section 6 of the Acts and which authorizes exploration
for, and development and production of, specific minerals; or the area
covered by that authorization.
Lessee means the person authorized by a lease, or an approved
assignment thereof, to explore for and develop and produce the leased
deposits in accordance with the regulations in this chapter. The term
includes all parties holding that authority by or through the lessee.
Major Federal action means any action or proposal by the Secretary
which is subject to the provisions of section 102(2)(C) of the National
Environmental Policy Act (NEPA) (i.e., an action which will have a
significant impact on the quality of the human environment requiring
preparation of an Environmental Impact Statement (EIS) pursuant to
section 102(2)(C) of NEPA).

[[Page 524]]

Marine environment means the physical, atmospheric, and biological
components, conditions, and factors which interactively determine the
productivity, state, condition, and quality of the marine ecosystem,
including the waters of the high seas, the contiguous zone, transitional
and intertidal areas, salt marshes, and wetlands within the coastal zone
and on the OCS.
Minerals include oil, gas, sulphur, geopressured-geothermal and
associated resources, and all other minerals which are authorized by an
Act of Congress to be produced from ``public lands'' as defined in
section 103 of the Federal Land Policy and Management Act of 1976.
OCS mineral means any mineral deposit or accretion found on or below
the surface of the seabed but does not include oil, gas, or sulphur;
salt or sand and gravel intended for use in association with the
development of oil, gas, or sulphur; or source materials essential to
production of fissionable materials which are reserved to the United
States pursuant to section 12(e) of the Act.
Operator means the individual, partnership, firm, or corporation
having control or management of operations on the lease or a portion
thereof. The operator may be a lessee, designated agent of the lessee,
or holder of rights under an approved operating agreement.
Outer Continental Shelf means all submerged lands lying seaward and
outside of the area of lands beneath navigable waters as defined in
section 2 of Submerged Lands Act (43 U.S.C. 1301) and of which the
subsoil and seabed appertain to the United States and are subject to its
jurisdiction and control.
Person means a citizen or national of the United States; an alien
lawfully admitted for permanent residency in the United States as
defined in 8 U.S.C. 1101(a)(20); a private, public, or municipal
corporation organized under the laws of the United States or of any
State or territory thereof; an association of such citizens, nationals,
resident aliens or private, public, or municipal corporations, States,
or political subdivisions of States; or anyone operating in a manner
provided for by treaty or other applicable international agreements. The
term does not include Federal Agencies.
Secretary means the Secretary of the Interior or an official
authorized to act on the Secretary's behalf.
Testing means removing bulk samples for processing tests and
feasibility studies and/or the testing of mining equipment to obtain
information needed to develop a detailed Mining Plan.

Sec. 582.4 Opportunities for review and comment.

(a) In carrying out BOEM's responsibilities under the Act and
regulations in this part, the Director shall provide opportunities for
Governors of adjacent States, State/Federal task forces, lessees and
operators, other Federal Agencies, and other interested parties to
review proposed activities described in a Delineation, Testing, or
Mining Plan together with an analysis of potential impacts on the
environment and to provide comments and recommendations for the
disposition of the proposed plan.
(b)(1) For Delineation Plans, the adjacent State Governor(s) shall
be notified by the Director within 15 days following the submission of a
request for approval of a Delineation Plan. Notification shall include a
copy of the proposed Delineation Plan and the accompanying environmental
information. The adjacent State Governor(s) who wishes to comment on a
proposed Delineation Plan may do so within 30 days of the receipt of the
proposed plan and the accompanying information.
(2) In cases where an Environmental Assessment is to be prepared,
the Director's invitation to provide comments may allow the adjacent
State Governor(s) more than 30 days following receipt of the proposed
plan to provide comments.
(3) The Director shall notify Federal Agencies, as appropriate, with
a copy of the proposed Delineation Plan and the accompanying
environmental information within 15 days following the submission of the
request. Agencies that wish to comment on a proposed Delineation Plan
shall do so within 30 days following receipt of the plan and the
accompanying information.
(c)(1) For Testing Plans, the adjacent State Governor(s) shall be
notified by

[[Page 525]]

the Director within 20 days following submission of a request for
approval of a proposed Testing Plan. Notification shall include a copy
of the proposed Testing Plan and the accompanying environmental
information. The adjacent State Governor(s) who wishes to comment on a
proposed Testing Plan may do so within 60 days of the receipt of a plan
and the accompanying information.
(2) In cases where an EIS is to be prepared, the Director's
invitation to provide comments may allow the adjacent State Governor(s)
more than 60 days following receipt of the proposed plan to provide
comments.
(3) The Director shall notify Federal Agencies, as appropriate, with
a copy of the proposed Testing Plan and the accompanying environmental
information within 20 days following the submission of the request.
Agencies that wish to comment on a proposed Testing Plan shall do so
within 60 days following receipt of the plan and the accompanying
information.
(d)(1) For Mining Plans, the adjacent State Governor(s) shall be
notified by the Director within 20 days following the submission of a
request for approval of a proposed Mining Plan. Notification shall
include a copy of the proposed Mining Plan and the accompanying
environmental information. The adjacent State Governor(s) who wishes to
comment on a proposed Mining Plan may do so within 60 days of the
receipt of a plan and the accompanying information.
(2) In cases where an EIS is to be prepared, the Director's
invitation to provide comments may allow the adjacent State Governor(s)
more than 60 days following receipt of the proposed plan to provide
comments.
(3) The Director shall notify Federal Agencies, as appropriate, with
a copy of the proposed Mining Plan and the accompanying environmental
information within 20 days following the submission of the request.
Agencies that wish to comment on a proposed Mining Plan shall do so
within 60 days following receipt of the plan and the accompanying
information.
(e) When an adjacent State Governor(s) has provided comments
pursuant to paragraphs (b), (c), and (d) of this section, the
Governor(s) shall be given, in writing, a list of recommendations which
are adopted and the reasons for rejecting any of the recommendations of
the Governor(s) or for implementing any alternative means identified
during consultations with the Governor(s).

Sec. 582.5 Disclosure of data and information to the public.

(a) The Director shall make data, information, and samples available
in accordance with the requirements and subject to the limitations of
the Act, the Freedom of Information Act (5 U.S.C. 552), and the
implementing regulations (43 CFR part 2).
(b) Geophysical data, processed G&G information, interpreted G&G
information, and other data and information submitted pursuant to the
requirements of this part shall not be available for public inspection
without the consent of the lessee so long as the lease remains in
effect, unless the Director determines that earlier limited release of
such information is necessary for the unitization of operations on two
or more leases, to ensure proper Mining Plans for a common orebody, or
to promote operational safety. When the Director determines that early
limited release of data and information is necessary, the data and
information shall be shown only to persons with a direct interest in the
affected lease(s), unitization agreement, or joint Mining Plan.
(c) Geophysical data, processed geophysical information, and
interpreted geophysical information collected on a lease with high
resolution systems (including, but not limited to, bathymetry, side-scan
sonar, subbottom profiler, and magnetometer) in compliance with
stipulations or orders concerning protection of environmental aspects of
the lease may be made available to the public 60 days after submittal to
the Director, unless the lessee can demonstrate to the satisfaction of
the Director that release of the information or data would unduly damage
the lessee's competitive position.

[[Page 526]]

Sec. 582.6 Disclosure of data and information to an adjacent State.

(a) Proprietary data, information, and samples submitted to BOEM
pursuant to the requirements of this part shall be made available for
inspection by representatives of adjacent State(s) upon request by the
Governor(s) in accordance with paragraphs (b), (c), and (d) of this
section.
(b) Disclosure shall occur only after the Governor has entered into
an agreement with the Secretary providing that:
(1) The confidentiality of the information shall be maintained;
(2) In any action commenced against the Federal Government or the
State for failure to protect the confidentiality of proprietary
information, the Federal Government or the State, as the case may be,
may not raise as a defense any claim of sovereign immunity or any claim
that the employee who revealed the proprietary information, which is the
basis of the suit, was acting outside the scope of the person's
employment in revealing the information;
(3) The State agrees to hold the United States harmless for any
violation by the State or its employees or contractors of the agreement
to protect the confidentiality of proprietary data, information, and
samples; and
(c) The data, information, and samples available for inspection by
representatives of adjacent State(s) pursuant to an agreement shall be
related to leased lands.

Sec. 582.7 Jurisdictional controversies.

Subpart B_Jurisdiction and Responsibilities of Director

Sec. 582.10 Jurisdiction and responsibilities of Director.

Subject to the authority of the Secretary, the following activities
are subject to the regulations in this part and are under the
jurisdiction of the Director: Exploration, testing, and mining
operations together with the associated environmental protection
measures needed to permit those activities to be conducted in an
environmentally responsible manner; handling, measurement, and
transportation of OCS minerals; and other operations and activities
conducted pursuant to a lease issued under 30 CFR part 581, or pursuant
to a right of use and easement granted under this part, by or on behalf
of a lessee or the holder of a right of use and easement.

Sec. 582.11 Director's authority.

(a) In the exercise of jurisdiction under Sec. 582.10, the Director
is authorized and directed to act upon the requests, applications, and
notices submitted under the regulations in this part; to issue either
written or oral orders to govern lease operations; and to require
compliance with applicable laws, regulations, and lease terms so that
all operations conform to sound conservation practices and are conducted
in a manner which is consistent with the following:
(1) Make such OCS minerals available to meet the nation's needs in a
timely manner;
(2) Balance OCS mineral resource development with protection of the
human, marine, and coastal environments;
(3) Ensure the public a fair and equitable return on OCS minerals
leased on the OCS; and
(4) Foster and encourage private enterprise.
(b)(1) The Director is to be provided ready access to all OCS
mineral resource data and all environmental data acquired by the lessee
or holder of a right of use and easement in the course of operations on
a lease or right of use and easement and may require a lessee or holder
to obtain additional environmental data when deemed necessary to

[[Page 527]]

assure adequate protection of the human, marine, and coastal
environments.
(2) The Director is to be provided an opportunity to inspect, cut,
and remove representative portions of all samples acquired by a lessee
in the course of operations on the lease.
(c) In addition to the rights and privileges granted to a lessee
under any lease issued or maintained under the Act, on request, the
Director may grant a lessee, subject to such conditions as the Director
may prescribe, a right of use and easement to construct and maintain
platforms, artificial islands, and/or other installations and devices
which are permanently or temporarily attached to the seabed and which
are needed for the conduct of leasehold exploration, testing,
development, production, and processing activities or other leasehold
related operations whether on or off the lease.
(d)(1) The Director may approve the consolidation of two or more OCS
mineral leases or portions of two or more OCS mineral leases into a
single mining unit requested by lessees, or the Director may require
such consolidation when the operation of those leases or portions of
leases as a single mining unit is in the interest of conservation of the
natural resources of the OCS or the prevention of waste. A mining unit
may also include all or portions of one or more OCS mineral leases with
all or portions of one or more adjacent State leases for minerals in a
common orebody. A single unit operator shall be responsible for
submission of required Delineation, Testing, and Mining Plans covering
OCS mineral operations for an approved mining unit.
(2) Operations such as exploration, testing, and mining activities
conducted in accordance with an approved plan on any lease or portion of
a lease which is subject to an approved mining unit shall be considered
operations on each of the leases that is made subject to the approved
mining unit.
(3) Minimum royalty paid pursuant to a Federal lease, which is
subject to an approved mining unit, is creditable against the production
royalties allocated to that Federal lease during the lease year for
which the minimum royalty is paid.
(4) Any OCS minerals produced from State and Federal leases which
are subject to an approved mining unit shall be accounted for separately
unless a method of allocating production between State and Federal
leases has been approved by the Director and the appropriate State
official.

Sec. 582.12 Director's responsibilities.

[[Page 528]]

marine, coastal, or human environment, and the proposed activity cannot
be modified to avoid the conditions.
(3) The Director shall notify the lessee in writing of the reasons
for disapproving a Delineation Plan or for requiring modification of a
plan and the conditions that must be met for plan approval.
(c)(1) In the evaluation of a Testing Plan, the Director shall
consider whether the plan is consistent with:
(i) The provisions of the lease;
(ii) The provisions of the Act;
(iii) The provisions of the regulations prescribed under the Act;
(iv) Other applicable Federal law;
(v) Environmental, safety, and health requirements; and
(vi) The statutory requirement to protect property, natural
resources of the OCS, including mineral deposits (in areas leased or not
leased), and the National security or defense.
(2) Within 60 days following the release of a final EIS prepared
pursuant to NEPA or within 60 days following the comment period provided
in Sec. 582.4(c) of this part, the Director shall:
(i) Approve any Testing Plan which is consistent with the criteria
in paragraph (c)(1) of this section;
(ii) Require the lessee to modify any Testing Plan which is
inconsistent with the criteria in paragraph (c)(1) of this section; or
(iii) Disapprove any Testing Plan when the Director determines the
existence of exceptional geological conditions in the lease area,
exceptional resource values in the marine or coastal environment, or
other exceptional circumstances and that (A) implementation of the
activities described in the plan would probably cause serious harm and
damage to life (including fish and other aquatic life), to property, to
any mineral deposit (in areas leased or not leased), to the National
security or defense, or to the marine, coastal, or human environments;
(B) that the threat of harm or damage will not disappear or decrease to
an acceptable extent within a reasonable period of time; and (C) the
advantages of disapproving the Testing Plan outweigh the advantages of
development and production of the OCS mineral resources.
(3) The Director shall notify the lessee in writing of the reason(s)
for disapproving a Testing Plan or for requiring modification of a
Testing Plan and the conditions that must be met for approval of the
plan.
(d)(1) In the evaluation of a Mining Plan, the Director shall
consider whether the plan is consistent with:
(i) The provisions of the lease;
(ii) The provisions of the Act;
(iii) The provisions of the regulations prescribed under the Act;
(iv) Other applicable Federal law;
(v) Environmental, safety, and health requirements; and
(vi) The statutory requirements to protect property, natural
resources of the OCS, including mineral deposits (in areas leased or not
leased), and the National security or defense.
(2) Within 60 days following the release of a final EIS prepared
pursuant to NEPA or within 60 days following the comment period provided
in Sec. 582.4(d) of this part, the Director shall:
(i) Approve any Mining Plan which is consistent with the criteria in
paragraph (d)(1) of this section;
(ii) Require the lessee to modify any Mining Plan which is
inconsistent with the criteria in paragraph (d)(1) of this section; or
(iii) Disapprove any Mining Plan when the Director determines the
existence of exceptional geological conditions in the lease area,
exceptional resource values in the marine or coastal environment, or
other exceptional circumstances, and that:
(A) Implementation of the activities described in the plan would
probably cause serious harm and damage to life (including fish and other
aquatic life), to property, to any mineral deposit (in areas leased or
not leased), to the National security or defense, or to the marine,
coastal, or human environments;
(B) That the threat of harm or damage will not disappear or decrease
to an acceptable extent within a reasonable period of time; and

[[Page 529]]

(C) The advantages of disapproving the Mining Plan outweigh the
advantages of development and production of the OCS mineral resources.
(3) The Director shall notify the lessee in writing of the reason(s)
for disapproving a Mining Plan or for requiring modification of a Mining
Plan and the conditions that must be met for approval of the plan.
(e)-(f) [Reserved]
(g) The Director shall establish practices and procedures to govern
the collection of all rents, royalties, and other payments due the
Federal Government in accordance with terms of the leasing notice, the
lease, and the applicable Royalty Management regulations listed in Sec.
581.26(i) of this chapter.
(h) [Reserved]

Sec. 582.13 [Reserved]

Sec. 582.14 Noncompliance, remedies, and penalties.

(a)(1) If the Director determines that a lessee has failed to comply
with applicable provisions of law; the regulations in this part; other
applicable regulations; the lease; the approved Delineation, Testing, or
Mining Plan; or the Director's orders or instructions, and the Director
determines that such noncompliance poses a threat of immediate, serious,
or irreparable damage to the environment, the mine or the deposit being
mined, or other valuable mineral deposits or other resources, the
Director shall order the lessee to take immediate and appropriate
remedial action to alleviate the threat. Any oral orders shall be
followed up by service of a notice of noncompliance upon the lessee by
delivery in person to the lessee or agent, or by certified or registered
mail addressed to the lessee at the last known address.
(2) If the Director determines that the lessee has failed to comply
with applicable provisions of law; the regulations in this part; other
applicable regulations; the lease; the requirements of an approved
Delineation, Testing, or Mining Plan; or the Director's orders or
instructions, and such noncompliance does not pose a threat of
immediate, serious, or irreparable damage to the environment, the mine
or the deposit being mined, or other valuable mineral deposits or other
resources, the Director shall serve a notice of noncompliance upon the
lessee by delivery in person to the lessee or agent or by certified or
registered mail addressed to the lessee at the last known address.
(b) A notice of noncompliance shall specify in what respect(s) the
lessee has failed to comply with the provisions of applicable law;
regulations; the lease; the requirements of an approved Delineation,
Testing, or Mining Plan; or the Director's orders or instructions, and
shall specify the action(s) which must be taken to correct the
noncompliance and the time limits within which such action must be
taken.
(c) Failure of a lessee to take the actions specified in the notice
of noncompliance within the time limit specified shall be grounds for a
suspension of operations and other appropriate actions, including but
not limited to the assessment of a civil penalty of up to $10,000 per
day for each violation that is not corrected within the time period
specified (43 U.S.C. 1350(b)).
(d) Whenever the Director determines that a violation of or failure
to comply with any provision of the Act; or any provision of a lease,
license, or permit issued pursuant to the Act; or any provision of any
regulation promulgated under the Act probably occurred and that such
apparent violation continued beyond notice of the violation and the
expiration of the reasonable time period allowed for corrective action,
the Director shall follow the procedures concerning remedies and
penalties in subpart N, Remedies and Penalties, of 30 CFR part 550 to
determine and assess an appropriate penalty.
(e) The remedies and penalties prescribed in this section shall be
concurrent and cumulative, and the exercise of one shall not preclude
the exercise of the other. Further, the remedies and penalties
prescribed in this section shall be in addition to any other remedies
and penalties afforded by any other law or regulation (43 U.S.C.
1350(e)).

Sec. 582.15 Cancellation of leases.

(a) Whenever the owner of a nonproducing lease fails to comply with
any

[[Page 530]]

of the provisions of the Act, the lease, or the regulations issued under
the Act, and the default continues for a period of 30 days after mailing
of notice by registered or certified letter to the lease owner at the
owner's record post office address, the Secretary may cancel the lease
pursuant to section 5(c) of the Act, and the lessee shall not be
entitled to compensation. Any such cancellation is subject to judicial
review as provided by section 23(b) of the Act.
(b) Whenever the owner of any producing lease fails to comply with
any of the provisions of the Act, the lease, or the regulations issued
under the Act, the Secretary may cancel the lease only after judicial
proceedings pursuant to section 5(d) of the Act, and the lessee shall
not be entitled to compensation.
(c) Any lease issued under the Act, whether producing or not, may be
canceled by the Secretary upon proof that it was obtained by fraud or
misrepresentation and after notice and opportunity to be heard has been
afforded to the lessee.
(d) The Secretary may cancel a lease in accordance with the
following:
(1) Cancellation may occur at any time if the Secretary determines
after a hearing that:
(i) Continued activity pursuant to such lease would probably cause
serious harm or damage to life (including fish and other aquatic life),
to property, to any mineral (in areas leased or not leased), to the
National security or defense, or to the marine, coastal, or human
environment;
(ii) The threat of harm or damage will not disappear or decrease to
an acceptable extent within a reasonable period of time; and
(iii) The advantages of cancellation outweigh the advantages of
continuing such lease in force.
(2) Cancellation shall not occur unless and until operations under
such lease shall have been under suspension or temporary prohibition by
the Secretary, with due extension of any lease term continuously for a
period of 5 years or for a lesser period upon request of the lessee;
(3) Cancellation shall entitle the lessee to receive such
compensation as is shown to the Secretary as being equal to the lesser
of:
(i) The fair value of the canceled rights as of the date of
cancellation, taking account of both anticipated revenues from the lease
and anticipated costs, including costs of compliance with all applicable
regulations and operating orders, liability for cleanup costs or
damages, or both, and all other costs reasonably anticipated on the
lease, or
(ii) The excess, if any, over the lessee's revenue from the lease
(plus interest thereon from the date of receipt to date of
reimbursement) of all consideration paid for the lease and all direct
expenditures made by the lessee after the date of issuance of such lease
and in connection with exploration or development, or both, pursuant to
the lease (plus interest on such consideration and such expenditures
from date of payment to date of reimbursement), except that in the case
of joint leases which are canceled due to the failure of one or more
partners to exercise due diligence, the innocent parties shall have the
right to seek damages for such loss from the responsible party or
parties and the right to acquire the interests of the negligent party or
parties and be issued the lease in question.
(iii) The lessee shall not be entitled to compensation where one of
the following circumstances exists when a lease is canceled:
(A) A producing lease is forfeited or is canceled pursuant to
section (5)(d) of the Act;
(B) A Testing Plan or Mining Plan is disapproved because the
lessee's failure to demonstrate compliance with the requirements of
applicable Federal law; or
(C) The lessee of a nonproducing lease fails to comply with a
provision of the Act, the lease, or regulations issued under the Act,
and the noncompliance continues for a period of 30 days or more after
the mailing of a notice of noncompliance by registered or certified
letter to the lessee.

[[Page 531]]

Subpart C_Obligations and Responsibilities of Lessees

Sec. 582.20 Obligations and responsibilities of lessees.

(a) The lessee shall comply with the provisions of applicable laws;
regulations; the lease; the requirements of the approved Delineation,
Testing, or Mining Plans; and other written or oral orders or
instructions issued by the Director when performing exploration,
testing, development, and production activities pursuant to a lease
issued under 30 CFR part 581. The lessee shall take all necessary
precautions to prevent waste and damage to oil, gas, sulphur, and other
OCS mineral-bearing formations and shall conduct operations in such
manner that does not cause or threaten to cause harm or damage to life
(including fish and other aquatic life); to property; to the National
security or defense; or to the marine, coastal, or human environment
(including onshore air quality). The lessee shall make all mineral
resource data and information and all environmental data and information
acquired by the lessee in the course of exploration, testing,
development, and production operations on the lease available to the
Director for examination and copying at the lease site or an onshore
location convenient to the Director.
(b) In all cases where there is more than one lease owner of record,
one person shall be designated payor for the lease. The payor shall be
responsible for making all rental, minimum royalty, and royalty
payments.
(c) In all cases where lease operations are not conducted by the
sole lessee, a ``designation of operator'' shall be submitted to and
accepted by the Director prior to the commencement of leasehold
operations. This designation when accepted will be recognized as
authority for the designee to act on behalf of the lessees and to
fulfill the lessees' obligations under the Act, the lease, and the
regulations of this part. All changes of address and any termination of
a designation of operator shall be reported immediately, in writing, to
the Director. In the case of a termination of a designation of operator
or in the event of a controversy between the lessee and the designated
operator, both the lessee and the designated operator will be
responsible for the protection of the interests of the lessor.
(d) When required by the Director or at the option of the lessee,
the lessee shall submit to the Director the designation of a local
representative empowered to receive notices, provide access to OCS
mineral and environmental data and information, and comply with orders
issued pursuant to the regulations of this part. If there is a change in
the designated representative, the Director shall be notified
immediately.
(e) Before beginning operations, the lessee shall inform the
Director in writing of any designation of a local representative under
paragraph (d) of this section and the address of the mine office
responsible for the exploration, testing, development, or production
activities; the lessee's temporary and permanent addresses; or the name
and address of the designated operator who will be responsible for the
operations, and who will act as the local representative of the lessee.
The Director shall also be informed of each change thereafter in the
address of the mine office or in the name or address of the local
representative.
(f) The holder of a right-of-use and easement shall exercise its
rights under the right of use and easement in accordance with the
regulations of this part.
(g) A lessee shall submit reports and maintain records in accordance
with Sec. 582.29 of this part.
(h) When an oral approval is given by BOEM in response to an oral
request under these regulations, the oral request shall be confirmed in
writing by the lessee or holder of a right of use and easement within 72
hours.
(i) The lessee is responsible for obtaining all permits and
approvals from BOEM, BSEE or other Agencies needed to carry out
exploration, testing, development, and production activities under a
lease issued under 30 CFR part 581 of this title.

Sec. 582.21 Plans, general.

(a) No exploration, testing, development, or production activities,
except

[[Page 532]]

preliminary activities, shall be commenced or conducted on any lease
except in accordance with a plan submitted by the lessee and approved by
the Director. Plans will not be approved before completion of
comprehensive technical and environmental evaluations to assure that the
activities described will be carried out in a safe and environmentally
responsible manner. Prior to the approval of a plan, the Director will
assure that the lessee is prepared to take adequate measures to prevent
waste; conserve natural resources of the OCS; and protect the
environment, human life, and correlative rights. The lessee shall
demonstrate to the satisfaction of the Director that the lease is in
good standing, the lessee is authorized and capable of conducting the
activities described in the plan, and that an acceptable bond has been
provided.
(b) Plans shall be submitted to the Director for approval. The
lessee shall submit the number of copies prescribed by the Director.
Such plans shall describe in detail the activities that are to be
conducted and shall demonstrate that the proposed exploration, testing,
development, and production activities will be conducted in an
operationally safe and environmentally responsible manner that is
consistent with the provisions of the lease, applicable laws, and
regulations. The Governor of an affected State and other Federal
Agencies shall be provided an opportunity to review and provide comments
on proposed Delineation, Testing, and Mining Plans and any proposal for
a significant modification to an approved plan. Following review,
including the technical and environmental evaluations, the Director
shall either approve, disapprove, or require the lessee to modify its
proposed plan.
(c) Lessees are not required to submit a Delineation or Testing Plan
prior to submittal of a proposed Testing or Mining Plan if the lessee
has sufficient data and information on which to base a Testing or Mining
Plan without carrying out postlease exploration and/or testing
activities. A Mining Plan may include proposed exploration or testing
activities where those activities are needed to obtain additional data
and information on which to base plans for future mining activities. A
Testing Plan may include exploration activities when those activities
are needed to obtain additional data or information on which to base
plans for future testing or mining activities.
(d) Preliminary activities are bathymetric, geological, geophysical,
mapping, and other surveys necessary to develop a comprehensive
Delineation, Testing, or Mining Plan. Such activities are those which
have no significant adverse impact on the natural resources of the OCS.
The lessee shall give notice to the Director at least 30 days prior to
initiating the proposed preliminary activities on the lease. The notice
shall describe in detail those activities that are to be conducted and
the time schedule for conducting those activities.
(e) Leasehold activities shall be carried out with due regard to
conservation of resources, paying particular attention to the wise
management of OCS mineral resources, minimizing waste of the leased
resource(s) in mining and processing, and preventing damage to unmined
parts of the mineral deposit and other resources of the OCS.

Sec. 582.22 Delineation Plan.

All exploration activities shall be conducted in accordance with a
Delineation Plan submitted by the lessee and approved by the Director.
The Delineation Plan shall describe the proposed activities necessary to
locate leased OCS minerals, characterize the quantity and quality of the
minerals, and generate other information needed for the development of a
comprehensive Testing or Mining Plan. A Delineation Plan at a minimum
shall include the following:
(a) The OCS mineral(s) or primary interest.
(b) A brief narrative description of the activities to be conducted
and how the activities will lead to the discovery and evaluation of a
commercially minable deposit on the lease.
(c) The name, registration, and type of equipment to be used,
including vessel types as well as their navigation and mobile
communication systems, and transportation corridors to be used between
the lease and shore.

[[Page 533]]

(d) Information showing that the equipment to be used (including the
vessel) is capable of performing the intended operation in the
environment which will be encountered.
(e) Maps showing the proposed locations of test drill holes, the
anticipated depth of penetration of test drill holes, the locations
where surficial samples were taken, and the location of proposed
geophysical survey lines for each surveying method being employed.
(f) A description of measures to be taken to avoid, minimize, or
otherwise mitigate air, land, and water pollution and damage to aquatic
and wildlife species and their habitats; any unique or special features
in the lease area; aquifers; other natural resources of the OCS; and
hazards to public health, safety, and navigation.
(g) A schedule indicating the starting and completion dates for each
proposed exploration activity.
(h) A list of any known archaeological resources on the lease and
measures to assure that the proposed exploration activities do not
damage those resources.
(i) A description of any potential conflicts with other uses and
users of the area.
(j) A description of measures to be taken to monitor the effects of
the proposed exploration activities on the environment in accordance
with Sec. 582.28(c) of this part.
(k) A detailed description of practices and procedures to effect the
abandonment of exploration activities, e.g., plugging of test drill
holes. The proposed procedures shall indicate the steps to be taken to
assure that test drill holes and other testing procedures which
penetrate the seafloor to a significant depth are properly sealed and
that the seafloor is left free of obstructions or structures that may
present a hazard to other uses or users of the OCS such as navigation or
commercial fishing.
(l) A detailed description of the cycle of all materials, the method
for discharge and disposal of waste and refuse, and the chemical and
physical characteristics of waste and refuse.
(m) A description of the potential environmental impacts of the
proposed exploration activities including the following:
(1) The location of associated port, transport, processing, and
waste disposal facilities and affected environment (e.g., maps, land
use, and layout);
(2) A description of the nature and degree of environmental impacts
and the domestic socioeconomic effects of construction and operation of
the associated facilities, including waste characteristics and toxicity;
(3) Any proposed mitigation measures to avoid or minimize adverse
impacts on the environment;
(4) A certificate of consistency with the federally approved State
coastal zone management program, where applicable; and
(5) Alternative sites and technologies considered by the lessee and
the reasons why they were not chosen.
(n) Any other information needed for technical evaluation of the
planned activity, such as sample analyses to be conducted at sea, and
the evaluation of potential environmental impacts.

Sec. 582.23 Testing Plan.

All testing activities shall be conducted in accordance with a
Testing Plan submitted by the lessee and approved by the Director. Where
a lessee needs more information to develop a detailed Mining Plan than
is obtainable under an approved Delineation Plan, to prepare feasibility
studies, to carry out a pilot program to evaluate processing techniques
or technology or mining equipment, or to determine environmental effects
by a pilot test mining operation, the lessee shall submit a
comprehensive Testing Plan for the Director's approval. Any OCS minerals
acquired during activities conducted under an approved Testing Plan will
be subject to the payment of royalty pursuant to the governing lease
terms. A Testing Plan at a minimum shall include the following:
(a) The nature and purpose of the proposed testing program.
(b) A comprehensive description of the activities to be performed
including descriptions of the proposed methods for analysis of samples
taken.
(c) A narrative description and maps showing water depths and the
locations

[[Page 534]]

of the proposed pilot mining or other testing activities.
(d) A comprehensive description of the method and manner in which
testing activities will be conducted and the results the lessee expects
to obtain as a result of those activities.
(e) The name, registration, and type of equipment to be used,
including vessel types together with their navigation and mobile
communication systems, and transportation corridors to be used between
the lease and shore.
(f) Information showing that the equipment to be used (including the
vessel) is capable of performing the intended operation in the
environment which will be encountered.
(g) A schedule specifying the starting and completion dates for each
of the testing activities.
(h) A list of known archaeological resources on the lease and
measures to be used to assure that the proposed testing activities do
not damage those resources.
(i) A description of any potential conflicts with other uses and
users of the area.
(j) A description of measures to be taken to avoid, minimize, or
otherwise mitigate air, land, and water pollution and damage to aquatic
and wildlife species and their habitat; any unique or special features
in the lease area, other natural resources of the OCS; and hazards to
public health, safety, and navigation.
(k) A description of the measures to be taken to monitor the impacts
of the proposed testing activities in accordance with Sec. 582.28(c) of
this part.
(l) A detailed description of the cycle of all materials including
samples and wastes, the method for discharge and disposal of waste and
refuse, and the chemical and physical characteristics of such waste and
refuse.
(m) A detailed description of practices and procedures to effect the
abandonment of testing activities, e.g., abandonment of a pilot mining
facility. The proposed procedures shall indicate the steps to be taken
to assure that mined areas do not pose a threat to the environment and
that the seafloor is left free of obstructions and structures that may
present a hazard to other uses or users of the OCS such as navigation or
commercial fishing.
(n) A description of potential environmental impacts of testing
activities including the following:
(1) The location of associated port, transport, processing, and
waste disposal facilities and affected environment (e.g., maps, land
use, and layout);
(2) A description of the nature and degree of potential
environmental impacts of the proposed testing activities and the
domestic socioeconomic effects of construction and operation of the
proposed testing facilities, including waste characteristics and
toxicity;
(3) Any proposed mitigation measures to avoid or minimize adverse
impacts on the environment;
(4) A certificate of consistency with the federally approved State
coastal zone management program, where applicable; and
(5) Alternate sites and technologies considered by the lessee and
the reasons why they were not selected.
(o) Any other information needed for technical evaluation of the
planned activities and for evaluation of the impact of those activities
on the human, marine, and coastal environments.

Sec. 582.24 Mining Plan.

All OCS mineral development and production activities shall be
conducted in accordance with a Mining Plan submitted by the lessee and
approved by the Director. A Mining Plan shall include comprehensive
detailed descriptions, illustrations, and explanations of the proposed
OCS mineral development, production, and processing activities and
accurately present the lessee's proposed plan of operation. A Mining
Plan at a minimum shall include the following:
(a) A narrative description of the mining activities including:
(1) The OCS mineral(s) or material(s) to be recovered;
(2) Estimates of the number of tons and grade(s) of ore to be
recovered;
(3) Anticipated annual production;
(4) Volume of ocean bottom expected to be disturbed (area and depth
of disruption) each year; and
(5) All activities of the mining cycle from extraction through
processing and waste disposal.

[[Page 535]]

(b) Maps of the lease showing water depths, the outline of the
mineral deposit(s) to be mined with cross sections showing thickness,
and the area(s) anticipated to be mined each year.
(c) The name, registration, and type of equipment to be used,
including vessel types as well as their navigation and mobile
communication systems, and transportation corridors to be used between
the lease and shore.
(d) Information showing that the equipment to be used (including the
vessel) is capable of performing the intended operation in the
environment which will be encountered.
(e) A description of equipment to be used in mining, processing, and
transporting of the ore.
(f) A schedule indicating the anticipated starting and completion
dates for each activity described in the plan.
(g) For onshore processing, a description of how OCS minerals are to
be processed and how the produced OCS minerals will be weighed, assayed,
and royalty determinations made.
(h) For at-sea processing, additional information including type and
size of installation or structures and the method of tailings disposal.
(i) A list of known archaeological resources on the lease and the
measures to be taken to assure that the proposed mining activities do
not damage those resources.
(j) Description of any potential conflicts with other uses and users
of the area.
(k) A detailed description of the nature and occurrence of the OCS
mineral deposit(s) in the leased area with adequate maps and sections.
(l) A detailed description of development and mining methods to be
used, the proposed sequence of mining or development, the expected
production rate, the method and location of the proposed processing
operation, and the method of measuring production.
(m) A detailed description of the method of transporting the
produced OCS minerals from the lease to shore and adequate maps showing
the locations of pipelines, conveyors, and other transportation
facilities and corridors.
(n) A detailed description of the cycle of all materials including
samples and wastes, the method of discharge and disposal of waste and
refuse, and the chemical and physical characteristics of the waste and
refuse.
(o) A description of measures to be taken to avoid, minimize, or
otherwise mitigate air, land, and water pollution and damage to aquatic
and wildlife species and their habitats; any unique or special features
in the lease area, aquifers, or other natural resources of the OCS; and
hazards to public health, safety, and navigation.
(p) A detailed description of measures to be taken to monitor the
impacts of the proposed mining and processing activities on the
environment in accordance with Sec. 582.28(c) of this part.
(q) A detailed description of practices and procedures to effect the
abandonment of mining and processing activities. The proposed procedures
shall indicate the steps to be taken to assure that mined areas on
tailing deposits do not pose a threat to the environment and that the
seafloor is left free of obstructions and structures that present a
hazard to other users or uses of the OCS such as navigation or
commercial fishing.
(r) A description of potential environmental impacts of mining
activities including the following:
(1) The location of associated port, transport, processing, and
waste disposal facilities and the affected environment (e.g., maps, land
use, and layout);
(2) A description of the nature and degree of potential
environmental impacts of the proposed mining activities and the domestic
socioeconomic effects of construction and operation of the associated
facilities, including waste characteristics and toxicity;
(3) Any proposed mitigation measures to avoid or minimize adverse
impacts on the environment;
(4) A certificate of consistency with the federally approved State
coastal zone management program, where applicable; and
(5) Alternative sites and technologies considered by the lessee and
the reasons why they were not chosen.
(s) Any other information needed for technical evaluation of the
proposed activities and for the evaluation of potential impacts on the
environment.

[[Page 536]]

Sec. 582.25 Plan modification.

Approved Delineation, Testing, and Mining Plans may be modified upon
the Director's approval of the changes proposed. When circumstances
warrant, the Director may direct the lessee to modify an approved plan
to adjust to changed conditions. If the lessee requests the change, the
lessee shall submit a detailed, written statement of the proposed
modifications, potential impacts, and the justification for the proposed
changes. Revision of an approved plan whether initiated by the lessee or
ordered by the Director shall be submitted to the Director for approval.
When the Director determines that a proposed revision could result in
significant change in the impacts previously identified and evaluated or
requires additional permits, the proposed plan revision shall be subject
to the applicable review and approval procedures of Sec. Sec. 582.21,
582.22, 582.23, and 582.24 of this part.

Sec. 582.26 Contingency Plan.

(a) When required by the Director, a lessee shall include a
Contingency Plan as part of its request for approval of a Delineation,
Testing, or Mining Plan. The Contingency Plan shall comply with the
requirements of Sec. 582.28(e) of this part.
(b) The Director may order or the lessee may request the Director's
approval of a modification of the Contingency Plan when such a change is
necessary to reflect any new information concerning the nature,
magnitude, and significance of potential equipment or procedural
failures or the effectiveness of the corrective actions described in the
Contingency Plan.

Sec. 582.27 Conduct of operations.

(a)-(h) [Reserved]
(i) Any bulk sampling or testing that is necessary to be conducted
prior to submission of a Mining Plan shall be in accordance with an
approved Testing Plan. The sale of any OCS minerals acquired under an
approved Testing Plan shall be subject to the payment of the royalty
specified in the lease to the United States.
(j)-(m) [Reserved]

Sec. 582.28 Environmental protection measures.

(a) Exploration, testing, development, production, and processing
activities proposed to be conducted under a lease will only be approved
by the Director upon the determination that the adverse impacts of the
proposed activities can be avoided, minimized, or otherwise mitigated.
The Director shall take into account the information contained in the
sale-specific environmental evaluation prepared in association with the
lease offering as well as the site- and operational-specific
environmental evaluations prepared in association with the review and
evaluation of the approved Delineation, Testing, or Mining Plan. The
Director's review of the air quality consequences of proposed OCS
activities will follow the practices and procedures specified in 30 CFR
250.194, Sec. Sec. 550.194, 550.218, 550.249, and 550.303.
(b) If the baseline data available are judged by the Director to be
inadequate to support an environmental evaluation of a proposed
Delineation, Testing, or Mining Plan, the Director may require the
lessee to collect additional environmental baseline data prior to the
approval of the activities proposed.
(c)(1) [Reserved]
(2) Monitoring of environmental effects shall include determination
of the spatial and temporal environmental changes induced by the
exploration, testing, development, production, and processing activities
on the flora and fauna of the sea surface, the water column, and/or the
seafloor.
(3)-(4) [Reserved]
(5) When prototype test mining is proposed, the lessee shall include
a monitoring strategy for assessing the impacts of the testing
activities and for developing a strategy for monitoring commercial-scale
recovery and mitigating the impacts of commercial-scale recovery more
effectively. At a minimum, the proposed monitoring activities shall
address specific concerns expressed in the lease-sale environmental
analysis.
(6) When required, the monitoring plan shall specify:

[[Page 537]]

(i) The sampling techniques and procedures to be used to acquire the
needed data and information;
(ii) The format to be used in analysis and presentation of the data
and information;
(iii) The equipment, techniques, and procedures to be used in
carrying out the monitoring program; and
(iv) The name and qualifications of person(s) designated to be
responsible for carrying out the environmental monitoring.
(d) [Reserved]
(e) In the event that equipment or procedural failure might result
in significant additional damage to the environment, the lessee shall
submit a Contingency Plan which specifies the procedures to be followed
to institute corrective actions in response to such a failure and to
minimize adverse impacts on the environment. Such procedures shall be
designed for the site and mining activities described in the approved
Delineation, Testing, or Mining Plan.

Sec. 582.29 Reports and records.

(a) A report of the amount and value of each OCS mineral produced
from each lease shall be made by the payor for the lease for each
calendar month, beginning with the month in which approved testing,
development, or production activities are initiated and shall be filed
in duplicate with the Director on or before the 20th day of the
succeeding month, unless an extension of time for the filing of such
report is granted by the Director. The report shall disclose accurately
and in detail all operations conducted during each month and present a
general summary of the status of leasehold activities. The report shall
be submitted each month until the lease is terminated or relinquished
unless the Director authorizes omission of the report during an approved
suspension of production. The report shall show for each calendar month
the location of each mining and processing activity; the number of days
operations were conducted; the identity, quantity, quality, and value of
each OCS mineral produced, sold, transferred, used or otherwise disposed
of; identity, quantity, and quality of an inventory maintained prior to
the point of royalty determination; and other information as may be
required by the Director.
(b) The lessee shall submit a status report on exploration and/or
testing activities under an approved Delineation or Testing Plan to the
Director within 30 days of the close of each calendar quarter which
shall include:
(1) A summary of activities conducted;
(2) A listing of all geophysical and geochemical data acquired and
developed such as acoustic or seismic profiling records;
(3) A map showing location of holes drilled and where bottom samples
were taken; and
(4) Identification of samples analyzed.
(c) Each lessee shall submit to the Director a report of exploration
and/or testing activities within 3 months after the completion of
operations. The final report of exploration and/or testing activities
conducted on the lease shall include:
(1) A description of work performed;
(2) Charts, maps, or plats depicting the area and leases in which
activities were conducted specifically identifying the lines of
geophysical traverses and/or the locations where geological activity was
conducted and/or the locations of other exploration and testing
activities;
(3) The dates on which the actual operations were performed;
(4) A narrative summary of any mineral occurrences; environmental
hazards; and effects of the activities on the environment, aquatic life,
archaeological resources, or other uses and users of the area in which
the activities were conducted;
(5) Such other descriptions of the activities conducted as may be
specified by the Director; and
(6) Records of all samples from core drilling or other tests made on
the lease. The records shall be in such form that the location and
direction of the samples can be accurately located on a map. The records
shall include logs of all strata penetrated and conditions encountered,
such as minerals, water, gas, or unusual conditions, and copies of
analyses of all samples analyzed.

[[Page 538]]

(d) The lessee shall report the results of environmental monitoring
activities required in Sec. 582.28 of this part and shall submit such
other environmental data as the Director may require to conform with the
requirements of these regulations.
(e)(1) All maps shall be appropriately marked with reference to
official lease boundaries and elevations marked with reference to sea
level. When required by the Director, vertical projections and cross
sections shall accompany plan views. The maps shall be kept current and
submitted to the Director annually, or more often when required by the
Director. The accuracy of maps furnished shall be certified by a
professional engineer or land surveyor.
(2) The lessee shall prepare such maps of the leased lands as are
necessary to show the geological conditions as determined from G&G
surveys, bottom sampling, drill holes, trenching, dredging, or mining.
All excavations shall be shown in such manner that the volume of OCS
minerals produced during a royalty period can be accurately ascertained.
(f) Any lessee who acquires rock, mineral, and core samples under a
lease shall keep a representative split of each geological sample and a
quarter longitudinal segment of each core for 5 years during which time
the samples shall be available for inspection at the convenience of the
Director who may take cuts of such cores, cuttings, and samples.
(g)(1) The lessee shall keep all original data and information
available for inspection or duplication, by the Director at the expense
of the lessor, as long as the lease continues in force. Should the
lessee choose to dispose of original data and information once the lease
has expired, said data and information shall be offered to the lessor
free of costs and shall, if accepted, become the property of the lessor.
(2) Navigation tapes showing the location(s) where samples were
taken and test drilling conducted shall be retained for as long as the
lease continues in force.
(h) Lessees shall maintain records in which will be kept an accurate
account of all ore and rock mined; all ore put through a mill; all
mineral products produced; all ore and mineral products sold,
transferred, used, or otherwise disposed of and to whom sold or
transferred, and the inventory weight, assay value, moisture content,
base sales price, dates, penalties, and price received. The percentage
of each of the mineral products recovered and the percentages lost shall
be shown. The records associated with activities on a lease shall be
available to the Director for auditing.
(i) When special forms or reports other than those referred to in
the regulations in this part may be necessary, instructions for the
filing of such forms or reports will be given by the Director.

Sec. 582.30 Right of use and easement.

(a) A right of use and easement that includes any area subject to a
lease issued or maintained under the Act shall be granted only after the
lessee has been notified by the requestor and afforded the opportunity
to comment on the request. A holder of a right under a right of use and
easement shall exercise that right in accordance with the requirements
of the regulations in this part. A right of use and easement shall be
exercised only in a manner which does not interfere unreasonably with
operations of any lessee on its lease.
(b) Once a right of use and easement has been exercised, the right
shall continue, beyond the termination of any lease on which it may be
situated, as long as it is demonstrated to the Director that the right
of use and easement is being exercised by the holder of the right and
that the right of use and easement continues to serve the purpose
specified in the grant. If the right of use and easement extends beyond
the termination of any lease on which the right may be situated or if it
is situated on an unleased portion of the OCS, the rights of all
subsequent lessees shall be subject to such right. Upon termination of a
right of use and easement, the holder of the right shall abandon the
premises in the same manner that a lessee abandons activities on a lease
to the satisfaction of the Director.

[[Page 539]]

Sec. 582.31 [Reserved]

Subpart D_Payments

Sec. 582.40 Bonds.

(a) Pursuant to the requirements for a bond in Sec. 581.33 of this
title, prior to the commencement of any activity on a lease, the lessee
shall submit a surety or personal bond to cover the lessee's royalty and
other obligations under the lease as specified in this section.
(b) All bonds furnished by a lessee or operator must be in a form
approved by the Deputy Director. A single copy of the required form is
to be executed by the principal or, in the case of surety bonds, by both
the principal and an acceptable surety.
(c) Only those surety bonds issued by qualified surety companies
approved by the Department of the Treasury shall be accepted (see
Department of Treasury Circular No. 570 and any supplemental or
replacement circulars).
(d) Personal bonds shall be accompanied by a cashier's check,
certified check, or negotiable U.S. Treasury bonds of an equal value to
the amount specified in the bond. Negotiable Treasury bonds shall be
accompanied by a proper conveyance of full authority to the Director to
sell such securities in case of default in the performance of the terms
and conditions of the lease.
(e) A bond in the minimum amount of $50,000 to cover the lessee's
obligations under the lease shall be submitted prior to the commencement
of any activity on a leasehold. A $50,000 bond shall not be required on
a lease if the lessee already maintains or furnishes a $300,000 bond
conditioned on compliance with the terms of leases for OCS minerals
other than oil, gas, and sulphur held by the lessee on the OCS for the
area in which the lease is located. A bond submitted pursuant to Sec.
556.58(a) of this chapter may be amended to include the aforementioned
condition for compliance. Prior to approval of a Delineation, Testing,
or Mining Plan, the bond amount shall be adjusted, if appropriate, to
cover the operations and activities described in the proposed plan.
(f) For the purposes of this section there are three areas:
(1) The Gulf of Mexico and the area offshore the Atlantic Ocean;
(2) The area offshore the Pacific Coast States of California,
Oregon, Washington, and Hawaii; and
(3) The area offshore the coast of Alaska.
(g) A separate bond shall be required for each area. An operator's
bond may be submitted for a specific lease(s) in the same amount as the
lessee's bond(s) applicable to the lease(s) involved.
(h) Where, upon a default, the surety makes a payment to the United
States of an obligation incurred under a lease, the face amount of the
surety bond and the surety's liability thereunder shall be reduced by
the amount of such payment.
(i) After default, the principal shall, within 6 months after notice
or within such shorter period as may be fixed by the Director, either
post a new bond or increase the existing bond to the amount previously
held. In lieu thereof, the principal may, within that time, file
separate or substitute bonds for each lease. Failure to meet these
requirements may result in a suspension of operations including
production on leases covered by such bonds.
(j) The Director shall not consent to termination of the period of
liability of any bond unless an acceptable alternative bond has been
filed or until all the terms and conditions of the lease covered by the
bond have been met.

[76 FR 64623, Oct. 18, 2011, as amended at 80 FR 57098, Sept. 22, 2015]

Sec. 582.41 Method of royalty calculation.

Sec. 582.42 Payments.

Rentals, royalties, and other payments due the Federal Government on
leases for OCS minerals shall be paid and reports submitted by the payor
for a lease in accordance with Sec. 581.26.

[[Page 540]]

Subpart E_Appeals

Sec. 582.50 Appeals.

See 30 CFR part 590 for instructions on how to appeal any order or
decision that we issue under this part.

PART 583_NEGOTIATED NONCOMPETITIVE AGREEMENTS FOR THE USE
OF OUTER CONTINENTAL SHELF SAND, GRAVEL, AND/OR SHELL RESOURCES--
Table of Contents

Subpart A_General

Sec.
583.100 What is BOEM's authority for information collection (IC)?
583.105 What is the purpose of this part and to whom does it apply?
583.110 What is BOEM's authority for this part?
583.115 What definitions do I need to know?
583.120 Who is qualified for a project?
583.125 What are my rights to seek reconsideration of an unfavorable
decision by BOEM?
583.130 What are the minimum contents of an agreement to use OCS sand,
gravel, and/or shell resources?

Subpart B--[Reserved]

Subpart C_Outer Continental Shelf Sand, Gravel, and/or Shell Resources
Negotiated Agreements

Sec.
583.300 How do I submit a request for an agreement?
583.305 How will BOEM determine if a project qualifies?
583.310 What process does BOEM use to technically and environmentally
evaluate a qualified project?
583.315 What is the process for negotiating and executing an agreement?
583.320 What kinds of information must be included in an agreement?
583.325 What is the effective date of an agreement?
583.330 How will BOEM enforce the agreement?
583.335 What is the term of the agreement?
583.340 What debarment or suspension obligations apply to transactions
and contracts related to a project?
583.345 What is the process for extending or modifying an agreement?
583.350 When can an agreement be terminated?

Authority: 43 U.S.C. 1334.

Source: 82 FR 45973, Oct. 3, 2017, unless otherwise noted.

Subpart A_General

Sec. 583.100 What is BOEM's authority for information collection (IC)?

The IC requirements contained in part 583 have been approved by OMB
under 44 U.S.C. 3501 and assigned control number 1010-0191. The
information is being collected to determine if the applicant for a
negotiated noncompetitive agreement (agreement) for the use of sand,
gravel, and/or shell resources on the Outer Continental Shelf (OCS) is
qualified to enter into such an agreement and to determine if the
requested action is warranted. Applicants and parties to an agreement
are required to respond to requests related to IC activities.

Sec. 583.105 What is the purpose of this part and to whom does it apply?

The regulations in this part provide procedures for entering into
negotiated noncompetitive agreements for the use of OCS sand, gravel,
and/or shell resources. The rules of this part apply exclusively to
negotiated noncompetitive use of OCS sand, gravel, and/or shell
resources and do not apply to competitive leasing of minerals, including
oil, gas, sulphur, geopressured-geothermal and associated resources, and
all other minerals that are authorized by an Act of Congress to be
produced from ``public lands'' as defined in section 103 of the Federal
Land Policy and Management Act of 1976, as amended (43 U.S.C. 1701 et
seq.).

Sec. 583.110 What is BOEM's authority for this part?

(a) Pursuant to authority granted by section 8(k) of the Outer
Continental Shelf Lands Act (OSCLA), as amended (43 U.S.C. 1337(k)), the
Secretary has authority to negotiate a noncompetitive agreement for the
use of OCS sand, gravel, and/or shell resources:
(1) In a program of, or project for, shore protection, beach
restoration, or coastal wetlands restoration undertaken by a Federal,
State, or local government agency; or
(2) In a construction project, other than a project described in
paragraph

[[Page 541]]

(a)(1) of this section, that is funded in whole or in part by or
authorized by the Federal Government.
(b) The Secretary has delegated authority to BOEM to administer the
negotiated noncompetitive agreement provisions of OCSLA and prescribe
the rules and regulations necessary to carry out those provisions.

Sec. 583.115 What definitions do I need to know?

The definitions at 30 CFR 550.105 apply to this part. In addition,
when used in this part, the following terms will have the meaning given
below:
Agreement means a negotiated noncompetitive agreement that
authorizes a person to use OCS sand, gravel, and/or shell resources in a
program of, or project for, shore protection, beach restoration or
coastal wetlands restoration undertaken by one or more Federal, state or
local government agencies, or in a construction project authorized by,
or funded in whole or in part by, the Federal government. The form of
the agreement will be a Memorandum of Agreement (if one or more of the
parties to the agreement, other than BOEM, is a Federal agency) or a
lease (if all of the parties to the agreement other than BOEM are non-
Federal agencies or persons).
Amendment means a modification to the agreement between BOEM and the
parties to the agreement that extends or modifies the terms of the
agreement.
Applicant means any person proposing to use OCS sand, gravel, and/or
shell resources for a shore protection, beach restoration or coastal
wetlands restoration project undertaken by a Federal, state or local
government agency, or a construction project authorized by, or funded in
whole or in part by, the Federal Government. If multiple persons or
Federal, state, or local governments, other than BOEM, partner on a
project they will be considered joint applicants.
BOEM means the Bureau of Ocean Energy Management of the U.S.
Department of the Interior (DOI).
Borrow area means the offshore geographic area(s) or region(s) where
OCS sand, gravel, and/or shell resources have been identified for
potential use in a specific project.
Federal agency means any department, agency, or instrumentality of
the United States.
Local government means the governing authority at the county or city
level with jurisdiction to administer a particular project(s).
Modification means the process whereby parties to an agreement and
BOEM mutually agree to change, alter or amend an existing agreement.
Placement area means the geographic area in which OCS sand, gravel,
and/or shell resources, used by agreement, will be placed pursuant to
that agreement.
Program means a group of related projects that may be the subject of
a negotiated noncompetitive agreement for the use of OCS sand, gravel,
and/or shell resources.
Project means an undertaking that may be the subject of a negotiated
noncompetitive agreement for the use of OCS sand, gravel, and/or shell
resources.
Secretary means the Secretary of the Interior.

Sec. 583.120 Who is qualified for a project?

(a) BOEM may enter into an agreement with any person proposing to
use OCS sand, gravel, and/or shell resources for a program of, or
project for, shore protection, beach restoration, or coastal wetlands
restoration undertaken by a Federal, state, or local government agency
or in a construction project that is funded in whole or in part by or
authorized by the Federal Government.
(b) To request an agreement under this part, the applicant must be:
(1) A Federal, state, or local government agency;
(2) A citizen or national of the United States;
(3) An alien lawfully admitted for permanent residence in the United
States, as defined in the Immigration and Nationality Act, as amended (8
U.S.C. 1101(a)(20));
(4) A private or public corporation organized under the laws of the
United States, or of any State or territory thereof; or

[[Page 542]]

(5) An association of such citizens, nationals, resident aliens, or
private or public corporations.
(c) When entering into an agreement under this part, all applicants
are subject to the requirements of 2 CFR part 180 and 2 CFR part 1400.

Sec. 583.125 What are my rights to seek reconsideration
of an unfavorable decision by BOEM?

(a) After being notified of disqualification or disapproval of an
agreement or modification, an unsuccessful applicant, or adversely
affected party to an agreement, may apply for reconsideration by the
Director.
(1) All applications for reconsideration must be submitted to the
Director within 15 days of being notified of disqualification or
disapproval of an agreement or modification, and must be accompanied by
a statement of reasons for the requested reconsideration, with one copy
also submitted to the program office whose decision is the subject of
the request for reconsideration.
(2) The Director will respond in writing within 30 days.
(b) No appeal rights are available under 30 CFR part 590 and 43 CFR
part 4, subpart E.

Sec. 583.130 What are the minimum contents of an agreement to use OCS sand,
gravel, and/or shell resources?

Any use of OCS sand, gravel, and/or shell resources in an agreement
will be negotiated on a case-by-case basis. The agreement will specify,
at a minimum, who may use the OCS sand, gravel, and/or shell resources;
the nature of the rights granted, including any terms and conditions and
environmental stipulations; and the location, type, and volume of OCS
sand, gravel, and/or shell resources. An authorization to use OCS sand,
gravel, and/or shell resources identified in an agreement is not
exclusive; BOEM may allow other entities to use OCS sand, gravel, and/or
shell resources from the same borrow area if these uses are determined
by BOEM to be non-conflicting and do not exceed the availability of the
OCS resource.

Subpart B--[Reserved]

Subpart C_Outer Continental Shelf Sand, Gravel, and/or Shell Resources
Negotiated Agreements

Sec. 583.300 How do I submit a request for an agreement?

Any person may submit a written request to BOEM to obtain an
agreement for the use of OCS sand, gravel, and/or shell resources for
use in a program of, or project for, shore protection, beach
restoration, or coastal wetlands restoration undertaken by a Federal,
state, or local government agency, or in a construction project that is
funded in whole or in part by or authorized by the Federal Government.
(a) The written request must include:
(1) A detailed description of the proposed project for which the OCS
sand, gravel, and/or shell resources will be used and how it qualifies
as a program or project eligible under OCSLA to use OCS sand, gravel, or
shell resources;
(2) A description of the proposed borrow area(s) and placement
area(s), along with maps with geographic coordinates depicting the
location of the desired borrow area(s), the OCS block number(s), OCS
Planning Area(s), OCS Protraction Diagram Designation(s), and the
placement area(s). These should include:
(i) A detailed set of digital (e.g., portable document format or
pdf) maps with coordinates and navigation features of the desired OCS
project area (including borrow area and other project features); and
(ii) Digital geo-referenced spatial and tabular data depicting the
borrow area with features, such as geological sampling locations and any
hard or live-bottom benthic habitat present;
(3) Any available geological and geophysical data used to select,
design, and delineate the borrow area(s) and potential borrow areas
considered but not selected for final design in digital format, geo-
referenced where relevant. These may include:
(i) Sediment sampling (sediment cores and grab samples) data such as
physical description sheets, photographs, core locations, and grain size
analysis; and
(ii) Geophysical data such as subbottom profiler, marine
magnetometer,

[[Page 543]]

and side-scan sonar data, and bathymetry including geo-referenced
navigation survey tracklines, shotpoints, and/or timestamps;
(4) Any other uses of the OCS or infrastructure in the borrow area
that are known to the applicant at the time of application submittal;
(5) A description of the environmental evaluations and corresponding
documents that have been completed or are being prepared that cover all
offshore and onshore components of the project, as applicable;
(6) A target date or date range when the OCS sand, gravel, and/or
shell resources will be needed;
(7) A description of the person or government entities undertaking
the project;
(8) A list of any permits, licenses or authorizations required for
the project and their current status;
(9) A description of any potential inconsistencies with state
coastal zone management plans and/or any other applicable state and
local statutes, regulations or ordinances;
(10) The name, title, telephone number, mailing address and email
address of any points of contact for any Federal agencies, state, or
local governments, and contractor(s) with whom the applicant has
contracted or intends to contract;
(11) A statement explaining who authorized the project and how the
project is to be funded, indicating whether the project is federally
funded, in whole or in part, and whether the project is authorized by
the Federal Government; and
(12) For any other Federal, state, or local government agency
identified in the application, the name, title, mailing address,
telephone number, and email address of both a primary and a secondary
point of contact for the agency.
(b) [Reserved]

Sec. 583.305 How will BOEM determine if a project qualifies?

BOEM will make a determination as to whether the project, as
described in Sec. 583.300, qualifies for a negotiated noncompetitive
agreement for the use of OCS sand, gravel, and/or shell resources.
Within 15 business days of receipt of the application, BOEM will
determine if the application is complete or will request additional
information. After it has determined the application is complete, BOEM
will review the application and notify the applicant in writing whether
the project qualifies for an agreement. In determining whether a project
qualifies for an agreement, BOEM will consider, among other criteria,
the following:
(a) The project purpose;
(b) Other uses of OCS sand, gravel, and/or shell resources from the
same borrow area that are currently or were previously authorized by
BOEM for other projects or programs, including the location, type and
volume of such resources;
(c) The project funding source(s) and amounts;
(d) The proposed design and feasibility of the project;
(e) Any potential environmental and safety risks associated with the
project;
(f) Other federal interests located near or within the specified
borrow area;
(g) Comments received from potentially affected state or local
governments, if any;
(h) The applicant's background and experience working on similar
projects or activities;
(i) Whether the project operations can be conducted in a manner that
protects the environment and promotes orderly development of OCS mineral
resources;
(j) Whether activities can be conducted in a manner that does not
pose a threat of serious harm or damage to, or waste of, any natural
resource, any life (including fish and other aquatic life), property, or
the marine, coastal, or human environment; and
(k) Whether the project is consistent with the requirements of
applicable statutes and their implementing regulations, which may
include, but are not limited to, the Endangered Species Act (ESA) (16
U.S.C. 1531 et seq.), the Marine Mammal Protection Act (MMPA) (16 U.S.C.
1361 et seq.), the Marine Debris Research, Prevention, and Reduction Act
(MDRPRA) (33 U.S.C. 1951 et seq.), the Marine Plastic Pollution Research
and Control Act (MPPRCA) (33

[[Page 544]]

U.S.C. 1901 et seq.), the Federal Water Pollution Control Act (FWPCA)
(33 U.S.C. 1381 et seq.), and the International Convention for the
Prevention of Pollution from Ships (MARPOL), MARPOL-Annex V Treaty.

Sec. 583.310 What process does BOEM use to technically and environmentally
evaluate a qualified project?

(a) Once BOEM has determined a project qualifies for an agreement,
BOEM will begin the project evaluation process to decide whether to
enter into a negotiated noncompetitive agreement.
(b) BOEM will coordinate with relevant Federal agencies, State, and
local governments and any potentially affected federally recognized
Indian tribes or Alaska Native Corporations in the project evaluation.
(c) BOEM will evaluate the project and additional information
provided pursuant to Sec. Sec. 583.300 and 583.305, to determine if the
information is sufficient to conduct necessary technical and
environmental reviews to comply with the requirements of applicable
statutes and regulations, which may include, but are not limited to:
OCSLA (43 U.S.C. 1331 et seq.), the National Environmental Policy Act
(NEPA) (42 U.S.C. 4321 et seq.), the ESA (16 U.S.C. 1531 et seq.), the
MMPA (16 U.S.C. 1361 et seq.), the Magnuson-Stevens Fishery Conservation
and Management Act (MSFCMA) (16 U.S.C. 1801 et seq.), the National
Historic Preservation Act (NHPA) (54 U.S.C. 300101 et seq.), and the
Coastal Zone Management Act (CZMA) (16 U.S.C. 1451 et seq.).
(d) BOEM will not enter into a negotiated noncompetitive agreement
with the applicant until the information requested for the evaluation
has been provided and BOEM has evaluated it.

Sec. 583.315 What is the process for negotiating and executing an agreement?

(a) Upon completion of the technical, environmental and other
evaluations established in Sec. Sec. 583.305 and 583.310, BOEM will
decide whether to enter into a negotiated noncompetitive agreement with
the applicant for use of OCS sand, gravel, or shell resources for its
proposed project.
(b) If BOEM decides not to enter into such an agreement, BOEM will
inform the applicant of its reasons for not doing so. An applicant may
ask the BOEM Director for reconsideration of this decision, in
accordance with Sec. 583.125(a).
(c) If BOEM has decided to enter into a negotiated noncompetitive
agreement with the applicant, BOEM will negotiate the terms and
conditions of the agreement with the applicant and prepare a draft
agreement for the applicant's review.
(d) After considering comments and suggestions from the applicant,
BOEM, at its discretion, may finalize the agreement and distribute it to
the applicant for signature.
(e) Upon receipt of the agreement with the applicant's signature,
BOEM will execute the agreement. A copy of the executed agreement will
be mailed to the parties.

Sec. 583.320 What kinds of information must be included in an agreement?

Every agreement is negotiated on a case-by-case basis, but at a
minimum, must include:
(a) An agreement number, as assigned by BOEM;
(b) The purpose of, and authorities for, the agreement;
(c) Designated and delineated borrow area(s);
(d) A project description, including the timeframe within which the
project is to be started and completed;
(e) The terms and conditions of the agreement, including any
reporting requirements, environmental mitigations, and operating
parameters;
(f) All obligations of the parties; and
(g) The signatures of appropriate individuals authorized to bind the
applicant and BOEM.

Sec. 583.325 What is the effective date of an agreement?

The agreement will become effective on the date when all parties to
the agreement have signed it.

Sec. 583.330 How will BOEM enforce the agreement?

(a) Failure to comply with any applicable law or any provision,
term, or condition of the agreement may result

[[Page 545]]

in the termination of the agreement, a referral to an appropriate
Federal or State agency for enforcement, or both. Termination of the
agreement for noncompliance will be in the sole discretion of the
Director.
(b) The failure to comply in a timely and satisfactory manner with
any provision, term or condition of the agreement may delay or prevent
BOEM's approval of future requests for use of OCS sand, gravel, and/or
shell resources on the part of the parties to the agreement.

Sec. 583.335 What is the term of the agreement?

(a) An agreement will terminate upon one of the following, whichever
occurs first:
(1) The agreement expires by its own terms, unless the term is
extended prior to expiration under Sec. 583.345;
(2) The project is terminated, as set forth in Sec. 583.350; or
(3) A party to the agreement notifies BOEM, in writing, that
sufficient OCS sand, gravel, and/or shell resources, up to the amount
authorized in the agreement, have been obtained to complete the project.
(b) Absent extraordinary circumstances, no agreement will be for a
term longer than five years from its effective date.

Sec. 583.340 What debarment or suspension obligations apply to transactions
and contracts related to a project?

The parties to an agreement must ensure that all contracts and
transactions related to an agreement issued under this part comply with
the suspension and debarment regulations in 2 CFR part 180 and 2 CFR
part 1400.

Sec. 583.345 What is the process for extending or modifying an agreement?

(a) Unless otherwise provided for in the agreement, the parties to
the agreement may submit to BOEM a written request to extend or modify
an agreement. BOEM is under no obligation to extend or modify an
agreement and cannot be held liable for the consequences of the
expiration of an agreement. With the exception of paragraph (b) of this
section, any such requests must be made at least 180 days before the
term of the agreement expires. BOEM will respond to the request for
modification within 30 days of receipt and request any necessary
information and evaluations to comply with Sec. 583.305. BOEM may
approve the request, disapprove it, or approve it with modifications
subject to the requirements of Sec. 583.305.
(1) If BOEM approves a request to extend or modify an agreement,
BOEM will draft an agreement modification for review by the parties to
the agreement in the form of an amendment to the original agreement. The
amendment will include:
(i) The agreement number, as assigned by BOEM;
(ii) The modification(s) agreed to;
(iii) Any additional mitigation required; and
(iv) The signatures of the parties to the agreement and BOEM.
(2) If BOEM disapproves a request to extend or modify an agreement,
BOEM will inform the parties to the agreement of the reasons in writing.
Parties to the agreement may ask the BOEM Director for reconsideration
in accordance with Sec. 583.125.
(b) By written request, for strictly minor modifications that do not
change the substance of the project or the analyzed environmental
effects of the project, including but not limited to, the change of a
business address, the substitution of a different Federal, State or
local government agency contact, or an extension of less than 30 days,
parties to the agreement may memorialize the minor modification in a
letter from BOEM to the parties indicating the request has been granted.

Sec. 583.350 When can an agreement be terminated?

(a) The Director will terminate any agreement issued under this part
upon proof that it was obtained by fraud or misrepresentation, after
notice and an opportunity to be heard has been afforded to the parties
of the agreement.
(b) The Director may immediately suspend and subsequently terminate
any agreement issued under this part when:
(1) There is noncompliance with the agreement, pursuant to Sec.
583.330 (a); or

[[Page 546]]

(2) It is necessary for reasons of national security or defense; or
(3) The Director determines that:
(i) Continued activity under the agreement would cause serious harm
or damage to natural resources; life (including human and wildlife);
property; the marine, coastal, or human environment; or sites,
structures, or objects of historical or archaeological significance;
(ii) The threat of harm or damage will not disappear or decrease to
an acceptable extent within a reasonable period of time; and
(iii) The advantages of termination outweigh the advantages of
continuing the agreement.
(c) The Director will immediately notify the parties to the
agreement of the suspension or termination. The Director will also mail
a letter to the parties to the agreement at their record post office
address with notice of any suspension or termination and the cause for
such action.
(d) In the event that BOEM terminates an agreement under this
section, none of the parties to the agreement will be entitled to
compensation as a result of expenses or lost revenues that may result
from the termination.

PART 585_RENEWABLE ENERGY AND ALTERNATE USES OF EXISTING FACILITIES
ON THE OUTER CONTINENTAL SHELF--Table of Contents

Subpart A_General Provisions

Sec.
585.100 Authority.
585.101 What is the purpose of this part?
585.102 What are BOEM's responsibilities under this part?
585.103 When may BOEM prescribe or approve departures from these
regulations?
585.104 Do I need a BOEM lease or other authorization to produce or
support the production of electricity or other energy product
from a renewable energy resource on the OCS?
585.105 What are my responsibilities under this part?
585.106 Who can hold a lease or grant under this part?
585.107 How do I show that I am qualified to be a lessee or grant
holder?
585.108 When must I notify BOEM if an action has been filed alleging
that I am insolvent or bankrupt?
585.109 When must I notify BOEM of mergers, name changes, or changes of
business form?
585.110 How do I submit plans, applications, reports, or notices
required by this part?
585.111 When and how does BOEM charge me processing fees on a case-by-
case basis?
585.112 Definitions.
585.113 How will data and information obtained by BOEM under this part
be disclosed to the public?
585.114 Paperwork Reduction Act statements--information collection.
585.115 Documents incorporated by reference.
585.116 Requests for information on the state of the offshore renewable
energy industry.
585.117 [Reserved]
585.118 What are my appeal rights?

Subpart B_Issuance of OCS Renewable Energy Leases

General Lease Information

585.200 What rights are granted with a lease issued under this part?
585.201 How will BOEM issue leases?
585.202 What types of leases will BOEM issue?
585.203 With whom will BOEM consult before issuance of a lease?
585.204 What areas are available for leasing consideration?
585.205 How will leases be mapped?
585.206 What is the lease size?
585.207-585.209 [Reserved]

Competitive Lease Process

585.210 How does BOEM initiate the competitive leasing process?
585.211 What is the process for competitive issuance of leases?
585.212 What is the process BOEM will follow if there is reason to
believe that competitors have withdrawn before the Final Sale
Notice is issued?
585.213 What must I submit in response to a Request for Interest or a
Call for Information and Nominations?
585.214 What will BOEM do with information from the Requests for
Information or Calls for Information and Nominations?
585.215 What areas will BOEM offer in a lease sale?
585.216 What information will BOEM publish in the Proposed Sale Notice
and Final Sale Notice?
585.217-585.219 [Reserved]

Competitive Lease Award Process

585.220 What auction format may BOEM use in a lease sale?

[[Page 547]]

585.221 What bidding systems may BOEM use for commercial leases and
limited leases?
585.222 What does BOEM do with my bid?
585.223 What does BOEM do if there is a tie for the highest bid?
585.224 What happens if BOEM accepts my bid?
585.225 What happens if my bid is rejected, and what are my appeal
rights?
585.226-585.229 [Reserved]

Noncompetitive Lease Award Process

585.230 May I request a lease if there is no Call?
585.231 How will BOEM process my unsolicited request for a
noncompetitive lease?
585.232 May I acquire a lease noncompetitively after responding to a
Request for Interest or Call for Information and Nominations?
585.233-585.234 [Reserved]

Commercial and Limited Lease Terms

585.235 If I have a commercial lease, how long will my lease remain in
effect?
585.236 If I have a limited lease, how long will my lease remain in
effect?
585.237 What is the effective date of a lease?
585.238 Are there any other renewable energy research activities that
will be allowed on the OCS?

Subpart C_Rights-of-Way Grants and Rights-of-Use and Easement Grants for
Renewable Energy Activities

ROW Grants and RUE Grants

585.300 What types of activities are authorized by ROW grants and RUE
grants issued under this part?
585.301 What do ROW grants and RUE grants include?
585.302 What are the general requirements for ROW grant and RUE grant
holders?
585.303 How long will my ROW grant or RUE grant remain in effect?
585.304 [Reserved]

Obtaining ROW Grants and RUE Grants

585.305 How do I request an ROW grant or RUE grant?
585.306 What action will BOEM take on my request?
585.307 How will BOEM determine whether competitive interest exists for
ROW grants and RUE grants?
585.308 How will BOEM conduct an auction for ROW grants and RUE grants?
585.309 When will BOEM issue a noncompetitive ROW grant or RUE grant?
585.310 What is the effective date of an ROW grant or RUE grant?
585.311-585.314 [Reserved]

Financial Requirements for ROW Grants and RUE Grants

585.315 What deposits are required for a competitive ROW grant or RUE
grant?
585.316 What payments are required for ROW grants or RUE grants?

Subpart D_Lease and Grant Administration

Noncompliance and Cessation Orders

585.400 What happens if I fail to comply with this part?
585.401 When may BOEM issue a cessation order?
585.402 What is the effect of a cessation order?
585.403-585.404 [Reserved]

Designation of Operator

585.405 How do I designate an operator?
585.406 Who is responsible for fulfilling lease and grant obligations?
585.407 [Reserved]

Lease or Grant Assignment

585.408 May I assign my lease or grant interest?
585.409 How do I request approval of a lease or grant assignment?
585.410 How does an assignment affect the assignor's liability?
585.411 How does an assignment affect the assignee's liability?
585.412-585.414 [Reserved]

Lease or Grant Suspension

585.415 What is a lease or grant suspension?
585.416 How do I request a lease or grant suspension?
585.417 When may BOEM order a suspension?
585.418 How will BOEM issue a suspension?
585.419 What are my immediate responsibilities if I receive a suspension
order?
585.420 What effect does a suspension order have on my payments?
585.421 How long will a suspension be in effect?
585.422-585.424 [Reserved]

Lease or Grant Renewal

585.425 May I obtain a renewal of my lease or grant before it
terminates?
585.426 When must I submit my request for renewal?
585.427 How long is a renewal?
585.428 What effect does applying for a renewal have on my activities
and payments?
585.429 What criteria will BOEM consider in deciding whether to renew a
lease or grant?
585.430-585.431 [Reserved]

[[Page 548]]

Lease or Grant Termination

585.432 When does my lease or grant terminate?
585.433 What must I do after my lease or grant terminates?
585.434 [Reserved]

Lease or Grant Relinquishment

585.435 How can I relinquish a lease or a grant or parts of a lease or
grant?

Lease or Grant Contraction

585.436 Can BOEM require lease or grant contraction?

Lease or Grant Cancellation

585.437 When can my lease or grant be canceled?

Subpart E_Payments and Financial Assurance Requirements

Payments

585.500 How do I make payments under this part?
585.501 What deposits must I submit for a competitively issued lease,
ROW grant, or RUE grant?
585.502 What initial payment requirements must I meet to obtain a
noncompetitive lease, ROW grant, or RUE grant?
585.503 What are the rent and operating fee requirements for a
commercial lease?
585.504 How are my payments affected if I develop my lease in phases?
585.505 What are the rent and operating fee requirements for a limited
lease?
585.506 What operating fees must I pay on a commercial lease?
585.507 What rent payments must I pay on a project easement?
585.508 What rent payments must I pay on ROW grants or RUE grants
associated with renewable energy projects?
585.509 Who is responsible for submitting lease or grant payments to
BOEM?
585.510 May BOEM reduce or waive my lease or grant payments?
585.511-585.514 [Reserved]

Financial Assurance Requirements for Commercial Leases

585.515 What financial assurance must I provide when I obtain my
commercial lease?
585.516 What are the financial assurance requirements for each stage of
my commercial lease?
585.517 How will BOEM determine the amounts of the supplemental and
decommissioning financial assurance requirements associated
with commercial leases?
585.518-585.519 [Reserved]

Financial Assurance for Limited Leases, ROW Grants, and RUE Grants

585.520 What financial assurance must I provide when I obtain my limited
lease, ROW grant, or RUE grant?
585.521 Do my financial assurance requirements change as activities
progress on my limited lease or grant?
585.522-585.524 [Reserved]

Requirements for Financial Assurance Instruments

585.525 What general requirements must a financial assurance instrument
meet?
585.526 What instruments other than a surety bond may I use to meet the
financial assurance requirement?
585.527 May I demonstrate financial strength and reliability to meet the
financial assurance requirement for lease or grant activities?
585.528 May I use a third-party guaranty to meet the financial assurance
requirement for lease or grant activities?
585.529 Can I use a lease- or grant-specific decommissioning account to
meet the financial assurance requirements related to
decommissioning?

Changes in Financial Assurance

585.530 What must I do if my financial assurance lapses?
585.531 What happens if the value of my financial assurance is reduced?
585.532 What happens if my surety wants to terminate the period of
liability of my bond?
585.533 How does my surety obtain cancellation of my bond?
585.534 When may BOEM cancel my bond?
585.535 Why might BOEM call for forfeiture of my bond?
585.536 How will I be notified of a call for forfeiture?
585.537 How will BOEM proceed once my bond or other security is
forfeited?
585.538-585.539 [Reserved]

Revenue Sharing with States

585.540 How will BOEM equitably distribute revenues to States?
585.541 What is a qualified project for revenue sharing purposes?
585.542 What makes a State eligible for payment of revenues?
585.543 Example of how the inverse distance formula works.

Subpart F_Plans and Information Requirements

585.600 What plans and information must I submit to BOEM before I
conduct activities on my lease or grant?
585.601 When am I required to submit my plans to BOEM?

[[Page 549]]

585.602 What records must I maintain?
585.603-585.604 [Reserved]

Site Assessment Plan and Information Requirements for Commercial Leases

585.605 What is a Site Assessment Plan (SAP)?
585.606 What must I demonstrate in my SAP?
585.607 How do I submit my SAP?
585.608-585.609 [Reserved]

Contents of the Site Assessment Plan

585.610 What must I include in my SAP?
585.611 What information and certifications must I submit with my SAP to
assist BOEM in complying with NEPA and other relevant laws?
585.612 How will my SAP be processed for Federal consistency under the
Coastal Zone Management Act?
585.613 How will BOEM process my SAP?

Activities Under an Approved SAP

585.614 When may I begin conducting activities under my approved SAP?
585.615 What other reports or notices must I submit to BOEM under my
approved SAP?
585.616 [Reserved]
585.617 What activities require a revision to my SAP, and when will BOEM
approve the revision?
585.618 What must I do upon completion of approved site assessment
activities?
585.619 [Reserved]

Construction and Operations Plan for Commercial Leases

585.620 What is a Construction and Operations Plan (COP)?
585.621 What must I demonstrate in my COP?
585.622 How do I submit my COP?
585.623-585.625 [Reserved]

Contents of the Construction and Operations Plan

585.626 What must I include in my COP?
585.627 What information and certifications must I submit with my COP to
assist the BOEM in complying with NEPA and other relevant
laws?
585.628 How will BOEM process my COP?
585.629 May I develop my lease in phases?
585.630 [Reserved]

Activities Under an Approved COP

585.631 When must I initiate activities under an approved COP?
585.632 What documents must I submit before I may construct and install
facilities under my approved COP?
585.633 How do I comply with my COP?
585.634 What activities require a revision to my COP, and when will BOEM
approve the revision?
585.635 What must I do if I cease activities approved in my COP before
the end of my commercial lease?
585.636 What notices must I provide BOEM following approval of my COP?
585.637 When may I commence commercial operations on my commercial
lease?
585.638 What must I do upon completion of my commercial operations as
approved in my COP or FERC license?
585.639 [Reserved]

General Activities Plan Requirements for Limited Leases, ROW Grants, and
RUE Grants

585.640 What is a General Activities Plan (GAP)?
585.641 What must I demonstrate in my GAP?
585.642 How do I submit my GAP?
585.643-585.644 [Reserved]

Contents of the General Activities Plan

585.645 What must I include in my GAP?
585.646 What information and certifications must I submit with my GAP to
assist BOEM in complying with NEPA and other relevant laws?
585.647 How will my GAP be processed for Federal consistency under the
Coastal Zone Management Act?
585.648 How will BOEM process my GAP?
585.649 [Reserved]

Activities Under an Approved GAP

585.650 When may I begin conducting activities under my GAP?
585.651 When may I construct complex or significant OCS facilities on my
limited lease or any facilities on my project easement
proposed under my GAP?
585.652 How long do I have to conduct activities under an approved GAP?
585.653 What other reports or notices must I submit to BOEM under my
approved GAP?
585.654 [Reserved]
585.655 What activities require a revision to my GAP, and when will BOEM
approve the revision?
585.656 What must I do if I cease activities approved in my GAP before
the end of my term?
585.657 What must I do upon completion of approved activities under my
GAP?

Cable and Pipeline Deviations

585.658 Can my cable or pipeline construction deviate from my approved
COP or GAP?
585.659 What requirements must I include in my SAP, COP, or GAP
regarding air quality?

[[Page 550]]

Subpart G_Facility Design, Fabrication, and Installation

Reports

585.700 What reports must I submit to BOEM before installing facilities
described in my approved SAP, COP, or GAP?
585.701 What must I include in my Facility Design Report?
585.702 What must I include in my Fabrication and Installation Report?
585.703 What reports must I submit for project modifications and
repairs?
585.704 [Reserved]

Certified Verification Agent

585.705 When must I use a Certified Verification Agent (CVA)?
585.706 How do I nominate a CVA for BOEM approval?
585.707 What are the CVA's primary duties for facility design review?
585.708 What are the CVA's or project engineer's primary duties for
fabrication and installation review?
585.709 When conducting onsite fabrication inspections, what must the
CVA or project engineer verify?
585.710 When conducting onsite installation inspections, what must the
CVA or project engineer do?
585.711 [Reserved]
585.712 What are the CVA's or project engineer's reporting requirements?
585.713 What must I do after the CVA or project engineer confirms
conformance with the Fabrication and Installation Report on my
commercial lease?
585.714 What records relating to SAPs, COPs, and GAPs must I keep?

Subpart H_Environmental and Safety Management, Inspections, and Facility
Assessments for Activities Conducted Under SAPs, COPs and GAPs

585.800 How must I conduct my activities to comply with safety and
environmental requirements?
585.801 How must I conduct my approved activities to protect marine
mammals, threatened and endangered species, and designated
critical habitat?
585.802 What must I do if I discover a potential archaeological resource
while conducting my approved activities?
585.803 How must I conduct my approved activities to protect essential
fish habitats identified and described under the Magnuson-
Stevens Fishery Conservation and Management Act?
585.804-585.809 [Reserved]

Safety Management Systems

585.810 What must I include in my Safety Management System?
585.811 When must I follow my Safety Management System?
585.812 [Reserved]

Maintenance and Shutdowns

585.813 When do I have to report removing equipment from service?
585.814 [Reserved]

Equipment Failure and Adverse Environmental Effects

585.815 What must I do if I have facility damage or an equipment
failure?
585.816 What must I do if environmental or other conditions adversely
affect a cable, pipeline, or facility?
585.817-585.819 [Reserved]

Inspections and Assessments

585.820 Will BOEM conduct inspections?
585.821 Will BOEM conduct scheduled and unscheduled inspections?
585.822 What must I do when BOEM conducts an inspection?
585.823 Will BOEM reimburse me for my expenses related to inspections?
585.824 How must I conduct self-inspections?
585.825 When must I assess my facilities?
585.826-585.829 [Reserved]

Incident Reporting and Investigation

585.830 What are my incident reporting requirements?
585.831 What incidents must I report, and when must I report them?
585.832 How do I report incidents requiring immediate notification?
585.833 What are the reporting requirements for incidents requiring
written notification?

Subpart I_Decommissioning

Decommissioning Obligations and Requirements

585.900 Who must meet the decommissioning obligations in this subpart?
585.901 When do I accrue decommissioning obligations?
585.902 What are the general requirements for decommissioning for
facilities authorized under my SAP, COP, or GAP?
585.903 What are the requirements for decommissioning FERC-licensed
hydrokinetic facilities?
585.904 Can I request a departure from the decommissioning requirements?

Decommissioning Applications

585.905 When must I submit my decommissioning application?

[[Page 551]]

585.906 What must my decommissioning application include?
585.907 How will BOEM process my decommissioning application?
585.908 What must I include in my decommissioning notice?

Facility Removal

585.909 When may BOEM authorize facilities to remain in place following
termination of a lease or grant?
585.910 What must I do when I remove my facility?
585.911 [Reserved]

Decommissioning Report

585.912 After I remove a facility, cable, or pipeline, what information
must I submit?

Compliance with an Approved Decommissioning Application

585.913 What happens if I fail to comply with my approved
decommissioning application?

Subpart J_Rights of Use and Easement for Energy- and Marine-Related
Activities Using Existing OCS Facilities

Regulated Activities

585.1000 What activities does this subpart regulate?
585.1001-585.1003 [Reserved]

Requesting an Alternate Use RUE

585.1004 What must I do before I request an Alternate Use RUE?
585.1005 How do I request an Alternate Use RUE?
585.1006 How will BOEM decide whether to issue an Alternate Use RUE?
585.1007 What process will BOEM use for competitively offering an
Alternate Use RUE?
585.1008-585.1009 [Reserved]

Alternate Use RUE Administration

585.1010 How long may I conduct activities under an Alternate Use RUE?
585.1011 What payments are required for an Alternate Use RUE?
585.1012 What financial assurance is required for an Alternate Use RUE?
585.1013 Is an Alternate Use RUE assignable?
585.1014 When will BOEM suspend an Alternate Use RUE?
585.1015 How do I relinquish an Alternate Use RUE?
585.1016 When will an Alternate Use RUE be cancelled?
585.1017 [Reserved]

Decommissioning an Alternate Use RUE

585.1018 Who is responsible for decommissioning an OCS facility subject
to an Alternate Use RUE?
585.1019 What are the decommissioning requirements for an Alternate Use
RUE?

Source: 76 FR 64623, Oct. 18, 2011, unless otherwise noted.

Subpart A_General Provisions

Sec. 585.100 Authority.

The authority for this part derives from amendments to subsection 8
of the Outer Continental Shelf Lands Act (OCS Lands Act) (43 U.S.C.
1337), as set forth in section 388(a) of the Energy Policy Act of 2005
(EPAct) (Pub. L. 109-58). The Secretary of the Interior delegated to the
Bureau of Ocean Energy Management (BOEM) the authority to regulate
activities under section 388(a) of the EPAct. These regulations
specifically apply to activities that:
(a) Produce or support production, transportation, or transmission
of energy from sources other than oil and gas; or
(b) Use, for energy-related purposes or for other authorized marine-
related purposes, facilities currently or previously used for activities
authorized under the OCS Lands Act.

Sec. 585.101 What is the purpose of this part?

The purpose of this part is to:
(a) Establish procedures for issuance and administration of leases,
right-of-way (ROW) grants, and right-of-use and easement (RUE) grants
for renewable energy production on the Outer Continental Shelf (OCS) and
RUEs for the alternate use of OCS facilities for energy or marine-
related purposes;
(b) Inform you and third parties of your obligations when you
undertake activities authorized in this part; and

[[Page 552]]

(c) Ensure that renewable energy activities on the OCS and
activities involving the alternate use of OCS facilities for energy or
marine-related purposes are conducted in a safe and environmentally
sound manner, in conformance with the requirements of subsection 8(p) of
the OCS Lands Act, other applicable laws and regulations, and the terms
of your lease, ROW grant, RUE grant, or Alternate Use RUE grant.
(d) This part will not convey access rights for oil, gas, or other
minerals.

Sec. 585.102 What are BOEM's responsibilities under this part?

(a) BOEM will ensure that any activities authorized in this part are
carried out in a manner that provides for:
(1) Safety;
(2) Protection of the environment;
(3) Prevention of waste;
(4) Conservation of the natural resources of the OCS;
(5) Coordination with relevant Federal agencies (including, in
particular, those agencies involved in planning activities that are
undertaken to avoid conflicts among users and maximize the economic and
ecological benefits of the OCS, including multifaceted spatial planning
efforts);
(6) Protection of National security interests of the United States;
(7) Protection of the rights of other authorized users of the OCS;
(8) A fair return to the United States;
(9) Prevention of interference with reasonable uses (as determined
by the Secretary or Director) of the exclusive economic zone, the high
seas, and the territorial seas;
(10) Consideration of the location of and any schedule relating to a
lease or grant under this part for an area of the OCS, and any other use
of the sea or seabed;
(11) Public notice and comment on any proposal submitted for a lease
or grant under this part; and
(12) Oversight, inspection, research, monitoring, and enforcement of
activities authorized by a lease or grant under this part.
(b) BOEM will require compliance with all applicable laws,
regulations, other requirements, and the terms of your lease or grant
under this part and approved plans. BOEM will approve, disapprove, or
approve with conditions any plans, applications, or other documents
submitted to BOEM for approval under the provisions of this part.
(c) Unless otherwise provided in this part, BOEM may give oral
directives or decisions whenever prior BOEM approval is required under
this part. BOEM will document in writing any such oral directives within
10 business days.
(d) BOEM will establish practices and procedures to govern the
collection of all payments due to the Federal Government, including any
cost recovery fees, rents, operating fees, and other fees or payments.
BOEM will do this in accordance with the terms of this part, the leasing
notice, the lease or grant under this part, and applicable Office of
Natural Resources Revenue regulations or guidance.
(e) BOEM will provide for coordination and consultation with the
Governor of any State, the executive of any local government, and the
executive of any Indian Tribe that may be affected by a lease, easement,
or ROW under this subsection. BOEM may invite any affected State
Governor, representative of an affected Indian Tribe, and affected local
government executive to join in establishing a task force or other joint
planning or coordination agreement in carrying out our responsibilities
under this part.

[76 FR 64623, Oct. 18, 2011, as amended at 79 FR 21621, Apr. 17, 2014]

Sec. 585.103 When may BOEM prescribe or approve departures
from these regulations?

(a) BOEM may prescribe or approve departures from these regulations
when departures are necessary to:
(1) Facilitate the appropriate activities on a lease or grant under
this part;
(2) Conserve natural resources;
(3) Protect life (including human and wildlife), property, or the
marine, coastal, or human environment; or
(4) Protect sites, structures, or objects of historical or
archaeological significance.
(b) Any departure approved under this section and its rationale
must:
(1) Be consistent with subsection 8(p) of the OCS Lands Act;

[[Page 553]]

(2) Protect the environment and the public health and safety to the
same degree as if there was no approved departure from the regulations;
(3) Not impair the rights of third parties; and
(4) Be documented in writing.

Sec. 585.104 Do I need a BOEM lease or other authorization to produce
or support the production of electricity or other energy product
from a renewable energy resource on the OCS?

Except as otherwise authorized by law, it will be unlawful for any
person to construct, operate, or maintain any facility to produce,
transport, or support generation of electricity or other energy product
derived from a renewable energy resource on any part of the OCS, except
under and in accordance with the terms of a lease, easement, or ROW
issued pursuant to the OCS Lands Act.

Sec. 585.105 What are my responsibilities under this part?

As a lessee, applicant, operator, or holder of a ROW grant, RUE
grant, or Alternate Use RUE grant, you must:
(a) Design your projects and conduct all activities in a manner that
ensures safety and will not cause undue harm or damage to natural
resources, including their physical, atmospheric, and biological
components to the extent practicable; and take measures to prevent
unauthorized discharge of pollutants including marine trash and debris
into the offshore environment.
(b) Submit requests, applications, plans, notices, modifications,
and supplemental information to BOEM as required by this part;
(c) Follow up, in writing, any oral request or notification you
made, within 3 business days;
(d) Comply with the terms, conditions, and provisions of all reports
and notices submitted to BOEM, and of all plans, revisions, and other
BOEM approvals, as provided in this part;
(e) Make all applicable payments on time;
(f) Comply with the DOI's nonprocurement debarment regulations at 2
CFR part 1400;
(g) Include the requirement to comply with 2 CFR part 1400 in all
contracts and transactions related to a lease or grant under this part;
(h) Conduct all activities authorized by the lease or grant in a
manner consistent with the provisions of subsection 8(p) of the OCS
Lands Act;
(i) Compile, retain, and make available to BOEM representatives,
within the time specified by BOEM, any data and information related to
the site assessment, design, and operations of your project; and
(j) Respond to requests from the Director in a timely manner.

Sec. 585.106 Who can hold a lease or grant under this part?

(a) You may hold a lease or grant under this part if you can
demonstrate that you have the technical and financial capabilities to
conduct the activities authorized by the lease or grant and you are
a(n):
(1) Citizen or national of the United States;
(2) Alien lawfully admitted for permanent residence in the United
States as defined in 8 U.S.C. 1101(a)(20);
(3) Private, public, or municipal corporations organized under the
laws of any State of the United States, the District of Columbia, or any
territory or insular possession subject to U.S. jurisdiction;
(4) Association of such citizens, nationals, resident aliens, or
corporations;
(5) Executive Agency of the United States as defined in section 105
of Title 5 of the U.S. Code;
(6) State of the United States; and
(7) Political subdivision of States of the United States.
(b) You may not hold a lease or grant under this part or acquire an
interest in a lease or grant under this part if:
(1) You or your principals are excluded or disqualified from
participating in transactions covered by the Federal nonprocurement
debarment and suspension system (2 CFR part 1400), unless BOEM
explicitly has approved an exception for this transaction;
(2) BOEM determines or has previously determined after notice and
opportunity for a hearing that you or your principals have failed to
meet or

[[Page 554]]

exercise due diligence under any OCS lease or grant; or
(3) BOEM determines or has previously determined after notice and
opportunity for a hearing that you:
(i) Remained in violation of the terms and conditions of any lease
or grant issued under the OCS Lands Act for a period extending longer
than 30 days (or such other period BOEM allowed for compliance) after
BOEM directed you to comply; and
(ii) You took no action to correct the noncompliance within that
time period.

Sec. 585.107 How do I show that I am qualified to be a lessee
or grant holder?

(a) You must demonstrate your technical and financial capability to
construct, operate, maintain, and terminate/decommission projects for
which you are requesting authorization. Documentation can include:
(1) Descriptions of international or domestic experience with
renewable energy projects or other types of electric-energy-related
projects; and
(2) Information establishing access to sufficient capital to carry
out development.
(b) An individual must submit a written statement of citizenship
status attesting to U.S. citizenship. It does not need to be notarized
nor give the age of individual. A resident alien may submit a photocopy
of the Immigration and Naturalization Service form evidencing legal
status of the resident alien.
(c) A corporation or association must submit evidence, as specified
in the table in paragraph (d) of this section, acceptable to BOEM that:
(1) It is qualified to hold leases or grants under this part;
(2) It is authorized to conduct business under the laws of its
State;
(3) It is authorized to hold leases or grants on the OCS under the
operating rules of its business; and
(4) The persons holding the titles listed are authorized to bind the
corporation or association when conducting business with BOEM.
(d) Acceptable evidence under paragraph (c) of this section
includes, but is not limited to the following:

----------------------------------------------------------------------------------------------------------------
Requirements to qualify to hold leases or
grants on the OCS: Corp. Ltd. Prtnsp. Gen. Prtnsp. LLC Trust
----------------------------------------------------------------------------------------------------------------
(1) Original certificate or certified copy XX ............ ............ ............
from the State of incorporation stating
the name of the corporation exactly as it
must appear on all legal documents.
(2) Certified statement by Secretary/ XX ............ ............ ............
Assistant Secretary over corporate seal,
certifying that the corporation is
authorized to hold OCS leases.
(3) Evidence of authority of titled XX ............ ............ ............
positions to bind corporation, certified
by Secretary/Assistant Secretary over
corporate seal, including the following:
(i) Certified copy of resolution of
the board of directors with titles of
officers authorized to bind
corporation.
(ii) Certified copy of resolutions
granting corporate officer authority
to issue a power of attorney.
(iii) Certified copy of power of
attorney or certified copy of
resolution granting power of
attorney.
(4) Original certificate or certified copy ............ XX XX XX
of partnership or organization paperwork
registering with the appropriate State
official.
(5) Copy of articles of partnership or ............ XX XX XX
organization evidencing filing with
appropriate Secretary of State, certified
by Secretary/Assistant Secretary of
partnership or member or manager of LLC.
(6) Original certificate or certified copy ............ XX XX XX
evidencing State where partnership or LLC
is registered. Statement of authority to
hold OCS leases, certified by Secretary/
Assistant Secretary, OR original
paperwork registering with the
appropriate State official.
(7) Statements from each partner or LLC ............ XX XX XX
member indicating the following:

[[Page 555]]

(i) If a corporation or partnership,
statement of State of organization
and authorization to hold OCS leases,
certified by Secretary/Assistant
Secretary over corporate seal, if a
corporation.
(ii) If an individual, a statement of
citizenship.
(8) Statement from general partner, ............ XX ............ ............
certified by Secretary/Assistant
Secretary that:
(i) Each individual limited partner is
a U.S. citizen and;
(ii) Each corporate limited partner or
other entity is incorporated or
formed and organized under the laws
of a U.S. State or territory.
(9) Evidence of authority to bind ............ XX XX XX
partnership or LLC, if not specified in
partnership agreement, articles of
organization, or LLC regulations, i.e.,
certificates of authority from Secretary/
Assistant Secretary reflecting authority
of officers.
(10) Listing of members of LLC certified ............ ............ ............ XX
by Secretary/Assistant Secretary or any
member or manager of LLC.
(11) Copy of trust agreement or document ............ ............ ............ ............ XX
establishing the trust and all
amendments, properly certified by the
trustee with reference to where the
original documents are filed.
(12) Statement indicating the law under ............ ............ ............ ............ XX
which the trust is established and that
the trust is authorized to hold OCS
leases or grants.
----------------------------------------------------------------------------------------------------------------

(e) A local, State, or Federal executive entity must submit a
written statement that:
(1) It is qualified to hold leases or grants under this part; and
(2) The person(s) acting on behalf of the entity is authorized to
bind the entity when conducting business with us.
(f) BOEM may require you to submit additional information at any
time considering your bid or request for a noncompetitive lease.

Sec. 585.108 When must I notify BOEM if an action has been filed alleging
that I am insolvent or bankrupt?

You must notify BOEM within 3 business days after you learn of any
action filed alleging that you are insolvent or bankrupt.

Sec. 585.109 When must I notify BOEM of mergers, name changes,
or changes of business form?

You must notify BOEM in writing of any merger, name change, or
change of business form. You must notify BOEM as soon as practicable
following the merger, name change, or change in business form, but no
later than 120 days after the earliest of either the effective date, or
the date of filing the change or action with the Secretary of the State
or other authorized official in the State of original registry.

Sec. 585.110 How do I submit plans, applications, reports,
or notices required by this part?

(a) You must submit all plans, applications, reports, or notices
required by this part to BOEM at the following address: Deputy Director,
Bureau of Ocean Energy Management, 45600 Woodland Road, Sterling, VA
20166.
(b) Unless otherwise stated, you must submit one paper copy and one
electronic copy of all plans, applications, reports, or notices required
by this part.

[76 FR 64623, Oct. 18, 2011, as amended at 80 FR 57098, Sept. 22, 2015]

Sec. 585.111 When and how does BOEM charge me processing fees
on a case-by-case basis?

(a) BOEM will charge a processing fee on a case-by-case basis under
the procedures in this section with regard to any application or request
under this part if we decide at any time that the preparation of a
particular document

[[Page 556]]

or study is necessary for the application or request and it will have a
unique processing cost, such as the preparation of an Environmental
Assessment (EA) or Environmental Impact Statement (EIS).
(1) Processing costs will include contract oversight and efforts to
review and approve documents prepared by contractors, whether the
contractor is paid directly by the applicant or through BOEM.
(2) We may apply a standard overhead rate to direct processing
costs.
(b) We will assess the ongoing processing fee for each individual
application or request according to the following procedures:
(1) Before we process your application or request, we will give you
a written estimate of the proposed fee based on reasonable processing
costs.
(2) You may comment on the proposed fee.
(3) You may:
(i) Ask for our approval to perform, or to directly pay a contractor
to perform, all or part of any document, study, or other activity
according to standards we specify, thereby reducing our costs for
processing your application or request; or
(ii) Ask to pay us to perform, or contract for, all or part of any
document, study, or other activity.
(4) We will then give you the final estimate of the processing fee
amount with payment terms and instructions after considering your
comments and any BOEM-approved work you will do.
(i) If we encounter higher or lower processing costs than
anticipated, we will re-estimate our reasonable processing costs
following the procedures in paragraphs (b)(1) through (4) of this
section, but we will not stop ongoing processing unless you do not pay
in accordance with paragraph (b)(5) of this section.
(ii) Once processing is complete, we will refund to you the amount
of money that we did not spend on processing costs.
(5)(i) Consistent with the payment and billing terms provided in the
final estimate, we will periodically estimate what our reasonable
processing costs will be for a specific period and will bill you for
that period. Payment is due to us 30 days after you receive your bill.
We will stop processing your document if you do not pay the bill by the
date payment is due.
(ii) If a periodic payment turns out to be more or less than our
reasonable processing costs for the period, we will adjust the next
billing accordingly or make a refund. Do not deduct any amount from a
payment without our prior written approval.
(6) You must pay the entire fee before we will issue the final
document or take final action on your application or request.
(7) You may appeal our estimated processing costs in accordance with
the regulations in 43 CFR part 4. We will not process the document
further until the appeal is resolved, unless you pay the fee under
protest while the appeal is pending. If the appeal results in a decision
changing the proposed fee, we will adjust the fee in accordance with
paragraph (b)(5)(ii) of this section. If we adjust the fee downward, we
will not pay interest.

Sec. 585.112 Definitions.

Terms used in this part have the meanings as defined in this
section:
Affected local government means with respect to any activities
proposed, conducted, or approved under this part, any locality--
(1) That is, or is proposed to be, the site of gathering,
transmitting, or distributing electricity or other energy product, or is
otherwise receiving, processing, refining, or transshipping product, or
services derived from activities approved under this part;
(2) That is used, or is proposed to be used, as a support base for
activities approved under this part; or
(3) In which there is a reasonable probability of significant effect
on land or water uses from activities approved under this part.
Affected State means with respect to any activities proposed,
conducted, or approved under this part, any coastal State--
(1) That is, or is proposed to be, the site of gathering,
transmitting, or distributing energy or is otherwise receiving,
processing, refining, or transshipping products, or services derived

[[Page 557]]

from activities approved under this part;
(2) That is used, or is scheduled to be used, as a support base for
activities approved under this part; or
(3) In which there is a reasonable probability of significant effect
on land or water uses from activities approved under this part.
Alternate Use refers to the energy- or marine-related use of an
existing OCS facility for activities not otherwise authorized by this
subchapter or other applicable law.
Alternate Use RUE means a right-of-use and easement issued for
activities authorized under subpart J of this part.
Archaeological resource means any material remains of human life or
activities that are at least 50 years of age and that are of
archaeological interest (i.e., which are capable of providing scientific
or humanistic understanding of past human behavior, cultural adaptation,
and related topics through the application of scientific or scholarly
techniques, such as controlled observation, contextual measurement,
controlled collection, analysis, interpretation, and explanation).
Best available and safest technology means the best available and
safest technologies that BOEM determines to be economically feasible
wherever failure of equipment would have a significant effect on safety,
health, or the environment.
Best management practices mean practices recognized within their
respective industry, or by Government, as one of the best for achieving
the desired output while reducing undesirable outcomes.
BOEM means Bureau of Ocean Energy Management of the Department of
the Interior.
Certified Verification Agent (CVA) means an individual or
organization, experienced in the design, fabrication, and installation
of offshore marine facilities or structures, who will conduct specified
third-party reviews, inspections, and verifications in accordance with
this part.
Coastline means the same as the term ``coast line'' in section 2 of
the Submerged Lands Act (43 U.S.C. 1301(c)).
Commercial activities mean, for renewable energy leases and grants,
all activities associated with the generation, storage, or transmission
of electricity or other energy product from a renewable energy project
on the OCS, and for which such electricity or other energy product is
intended for distribution, sale, or other commercial use, except for
electricity or other energy product distributed or sold pursuant to
technology-testing activities on a limited lease. This term also
includes activities associated with all stages of development, including
initial site characterization and assessment, facility construction, and
project decommissioning.
Commercial lease means a lease issued under this part that specifies
the terms and conditions under which a person can conduct commercial
activities.
Commercial operations mean the generation of electricity or other
energy product for commercial use, sale, or distribution on a commercial
lease.
Decommissioning means removing BOEM-approved facilities and
returning the site of the lease or grant to a condition that meets the
requirements under subpart I of this part.
Director means the Director of the Bureau of Ocean Energy Management
(BOEM), of the U.S. Department of the Interior, or an official
authorized to act on the Director's behalf.
Distance means the minimum great circle distance.
Eligible State means a coastal State having a coastline (measured
from the nearest point) no more than 15 miles from the geographic center
of a qualified project area.
Facility means an installation that is permanently or temporarily
attached to the seabed of the OCS. Facilities include any structures;
devices; appurtenances; gathering, transmission, and distribution
cables; pipelines; and permanently moored vessels. Any group of OCS
installations interconnected with walkways, or any group of
installations that includes a central or primary installation with one
or more satellite or secondary installations, is a single facility. BOEM
may decide that the complexity of the installations justifies their
classification as separate facilities.
Geographic center of a project means the centroid (geometric center
point)

[[Page 558]]

of a qualified project area. The centroid represents the point that is
the weighted average of coordinates of the same dimension within the
mapping system, with the weights determined by the density function of
the system. For example, in the case of a project area shaped as a
rectangle or other parallelogram, the geographic center would be that
point where lines between opposing corners intersect. The geographic
center of a project could be outside the project area itself if that
area is irregularly shaped.
Governor means the Governor of a State or the person or entity
lawfully designated by or under State law to exercise the powers granted
to a Governor.
Grant means a right-of-way, right-of-use and easement, or alternate
use right-of-use and easement issued under the provisions of this part.
Human environment means the physical, social, and economic
components, conditions, and factors that interactively determine the
state, condition, and quality of living conditions, employment, and
health of those affected, directly or indirectly, by activities
occurring on the OCS.
Income, unless clearly specified to the contrary, refers to the
money received by the project owner or holder of the lease or grant
issued under this part. The term does not mean that project receipts
exceed project expenses.
Lease means an agreement authorizing the use of a designated portion
of the OCS for activities allowed under this part. The term also means
the area covered by that agreement, when the context requires.
Lessee means the holder of a lease, a BOEM-approved assignee, and,
when describing the conduct required of parties engaged in activities on
the lease, it also refers to the operator and all persons authorized by
the holder of the lease or operator to conduct activities on the lease.
Limited lease means a lease issued under this part that specifies
the terms and conditions under which a person may conduct activities on
the OCS that support the production of energy, but do not result in the
production of electricity or other energy product for sale,
distribution, or other commercial use exceeding a limit specified in the
lease.
Marine environment means the physical, atmospheric, and biological
components, conditions, and factors that interactively determine the
productivity, state, condition, and quality of the marine ecosystem.
These include the waters of the high seas, the contiguous zone,
transitional and intertidal areas, salt marshes, and wetlands within the
coastal zone and on the OCS.
Miles mean nautical miles, as opposed to statute miles.
Natural resources include, without limiting the generality thereof,
renewable energy, oil, gas, and all other minerals (as defined in
section 2(q) of the OCS Lands Act), and marine animal and marine plant
life.
Operator means the individual, corporation, or association having
control or management of activities on the lease or grant under this
part. The operator may be a lessee, grant holder, or a contractor
designated by the lessee or holder of a grant under this part.
Outer Continental Shelf (OCS) means all submerged lands lying
seaward and outside of the area of lands beneath navigable waters, as
defined in section 2 of the Submerged Lands Act (43 U.S.C. 1301), whose
subsoil and seabed appertain to the United States and are subject to its
jurisdiction and control.
Person means, in addition to a natural person, an association
(including partnerships and joint ventures); a Federal agency; a State;
a political subdivision of a State; a Native American Tribal government;
or a private, public, or municipal corporation.
Project, for the purposes of defining the source of revenues to be
shared, means a lease ROW, RUE, or Alternate Use RUE on which the
activities authorized under this part are conducted on the OCS. The term
``project'' may be used elsewhere in this rule to refer to these same
authorized activities, the facilities used to conduct these activities,
or to the geographic area of the project, i.e., the project area.
Project area means the geographic surface leased, or granted, for
the purpose of a specific project. If OCS acreage is granted for a
project under some form of agreement other than a lease (i.e., a ROW,
RUE, or Alternate Use

[[Page 559]]

RUE issued under this part), the Federal acreage granted would be
considered the project area. To avoid distortions in the calculation of
the geometric center of the project area, project easements issued under
this part are not considered part of the qualified project's area.
Project easement means an easement to which, upon approval of your
Construction and Operations Plan (COP) or General Activities Plan (GAP),
you are entitled as part of the lease for the purpose of installing,
gathering, transmission, and distribution cables, pipelines, and
appurtenances on the OCS as necessary for the full enjoyment of the
lease.
Renewable Energy means energy resources other than oil and gas and
minerals as defined in 30 CFR part 580. Such resources include, but are
not limited to, wind, solar, and ocean waves, tides, and current.
Revenues mean bonuses, rents, operating fees, and similar payments
made in connection with a project or project area. It does not include
administrative fees such as those assessed for cost recovery, civil
penalties, and forfeiture of financial assurance.
Right-of-use and easement (RUE) grant means an easement issued by
BOEM under this part that authorizes use of a designated portion of the
OCS to support activities on a lease or other use authorization for
renewable energy activities. The term also means the area covered by the
authorization.
Right-of-way (ROW) grant means an authorization issued by BOEM under
this part to use a portion of the OCS for the construction and use of a
cable or pipeline for the purpose of gathering, transmitting,
distributing, or otherwise transporting electricity or other energy
product generated or produced from renewable energy, but does not
constitute a project easement under this part. The term also means the
area covered by the authorization.
Secretary means the Secretary of the Interior or an official
authorized to act on the Secretary's behalf.
Significant archaeological resource means an archaeological resource
that meets the criteria of significance for eligibility for listing in
the National Register of Historic Places, as defined in 36 CFR 60.4 or
its successor.
Site assessment activities mean those initial activities conducted
to characterize a site on the OCS, such as resource assessment surveys
(e.g., meteorological and oceanographic) or technology testing,
involving the installation of bottom-founded facilities.
You and your means an applicant, lessee, the operator, or designated
operator, ROW grant holder, RUE grant holder, or Alternate Use RUE grant
holder under this part, or the designated agent of any of these, or the
possessive of each, depending on the context. The terms You and your
also include contractors and subcontractors of the entities specified in
the preceding sentence.
We, us, and our refer to the Bureau of Ocean Energy Management of
the Department of the Interior, or its possessive, depending on the
context.

[76 FR 64623, Oct. 18, 2011, as amended at 79 FR 21621, Apr. 17, 2014]

Sec. 585.113 How will data and information obtained by BOEM under this part
be disclosed to the public?

(a) BOEM will make data and information available in accordance with
the requirements and subject to the limitations of the Freedom of
Information Act (FOIA) (5 U.S.C. 552), the regulations contained in 43
CFR part 2 (Records and Testimony).
(b) BOEM will not release such data and information that we have
determined is exempt from disclosure under exemption 4 of FOIA. We will
review such data and information and objections of the submitter by the
following schedule to determine whether release at that time will result
in substantial competitive harm or disclosure of trade secrets.

------------------------------------------------------------------------
Then BOEM will review data and
If you have a . . . information for possible
release:
------------------------------------------------------------------------
(1) Commercial lease................... At the earlier of:
(i) 3 years after the
initiation of commercial
generation or
(ii) 3 years after the lease
terminates.

[[Page 560]]

(2) Limited lease...................... At 3 years after the lease
terminates.
(3) ROW or RUE grant................... At the earliest of:
(i) 10 years after the
approval of the grant;
(ii) Grant termination; or
(iii) 3 years after the
completion of construction
activities.
------------------------------------------------------------------------

(c) After considering any objections from the submitter, if we
determine that release of such data and information will result in:
(1) No substantial competitive harm or disclosure of trade secrets,
then the data and information will be released.
(2) Substantial competitive harm or disclosure of trade secrets,
then the data and information will not be released at that time but will
be subject to further review every 3 years thereafter.

Sec. 585.114 Paperwork Reduction Act statements--information collection.

(a) The Office of Management and Budget (OMB) has approved the
information collection requirements in 30 CFR part 585 under 44 U.S.C.
3501, et seq., and assigned OMB Control Number 1010-0176. The table in
paragraph (e) of this section lists the subpart in the rule requiring
the information and its title, summarizes the reasons for collecting the
information, and summarizes how BOEM uses the information.
(b) Respondents are primarily renewable energy applicants, lessees,
ROW grant holders, RUE grant holders, Alternate Use RUE grant holders,
and operators. The requirement to respond to the information collection
in this part is mandated under subsection 8(p) of the OCS Lands Act.
Some responses are also required to obtain or retain a benefit, or may
be voluntary.
(c) The Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq.)
requires us to inform the public that an agency may not conduct or
sponsor, and you are not required to respond to, a collection of
information unless it displays a currently valid OMB control number.
(d) Comments regarding any aspect of the collections of information
under this part, including suggestions for reducing the burden, should
be sent to the Information Collection Clearance Officer, Bureau of Ocean
Energy Management, 45600 Woodland Road, Sterling, VA 20166.
(e) BOEM is collecting this information for the reasons given in the
following table:

------------------------------------------------------------------------
30 CFR 585 subpart, title, and/or BOEM Reasons for collecting
Form (OMB Control No.) information and how used
------------------------------------------------------------------------
(1) Subpart A--General Provisions...... To inform BOEM of actions taken
to comply with general
operational requirements on
the OCS. To ensure that
operations on the OCS meet
statutory and regulatory
requirements, are safe and
protect the environment, and
result in diligent development
on OCS leases.
(2) Subpart B--Issuance of OCS To provide BOEM with
Renewable Energy Leases. information needed to
determine when to use a
competitive process for
issuing a renewable energy
lease, to identify auction
formats and bidding systems
and variables that we may use
when that determination is
affirmative, and to determine
the terms under which we will
issue renewable energy leases.
(3) Subpart C--ROW Grants and RUE To issue ROW grants and RUE
Grants for Renewable Energy Activities. grants for OCS renewable
energy activities that are not
associated with a BOEM-issued
renewable energy lease.
(4) Subpart D--Lease and Grant To ensure compliance with
Administration. regulations pertaining to a
lease or grant; assignment and
designation of operator; and
suspension, renewal,
termination, relinquishment,
and cancellation of leases and
grants.
(5) Subpart E--Payments and Financial To ensure that payments and
Assurance Requirements. financial assurance payments
for renewable energy leases
comply with subpart E.
(6) Subpart F--Plans and Information To enable BOEM to comply with
Requirements. the National Environmental
Policy Act (NEPA), the Coastal
Zone Management Act (CZMA),
and other Federal laws and to
ensure the safety of the
environment on the OCS.

[[Page 561]]

(7) Subpart G--Facility Design, To enable BOEM to review the
Fabrication, and Installation. final design, fabrication, and
installation of facilities on
a lease or grant to ensure
that these facilities are
designed, fabricated, and
installed according to
appropriate standards in
compliance with BOEM
regulations, and where
applicable, the approved plan.
(8) Subpart H--Environmental and Safety To ensure that lease and grant
Management, Inspections, and Facility operations are conducted in a
Assessments. manner that is safe and
protects the environment. To
ensure compliance with other
Federal laws, these
regulations, the lease or
grant, and approved plans.
(9) Subpart I--Decommissioning......... To determine that
decommissioning activities
comply with regulatory
requirements and approvals. To
ensure that site clearance and
platform or pipeline removal
are properly performed to
protect marine life and the
environment and do not
conflict with other users of
the OCS.
(10) Subpart J--RUEs for Energy and To enable BOEM to review
Marine-Related Activities Using information regarding the
Existing OCS Facilities. design, installation, and
operation of RUEs on the OCS,
to ensure that RUE operations
are safe and protect the
human, marine, and coastal
environment. To ensure
compliance with other Federal
laws, these regulations, the
RUE grant, and, where
applicable, the approved plan.
------------------------------------------------------------------------

[76 FR 64623, Oct. 18, 2011, as amended at 80 FR 57098, Sept. 22, 2015]

Sec. 585.115 Documents incorporated by reference.

(a) BOEM is incorporating by reference the documents listed in the
table in paragraph (e) of this section. The Director of the Federal
Register has approved this incorporation by reference according to 5
U.S.C. 552(a) and 1 CFR part 51.
(1) BOEM will publish, as a rule, any changes in the documents
incorporated by reference in the Federal Register.
(2) BOEM may amend by rule the list of industry standards
incorporated by reference of the document effective without prior
opportunity for public comment when BOEM determines that the revisions
to a document result in safety improvements or represent new industry
standard technology and do not impose undue costs on the affected
parties; and
(3) BOEM may make a rule, effective immediately, amending the list
of industry standards incorporated by reference if it determines good
cause exists for doing so under 5 U.S.C. 553.
(b) BOEM is incorporating each document or specific portion by
reference in the sections noted. The entire document is incorporated by
reference, unless the text of the corresponding sections in this part
calls for compliance with specific portions of the listed documents. In
each instance, the applicable document is the specific edition, or
specific edition and supplement, or specific addition and addendum cited
in this section.
(c) You may comply with a later edition of a specific document
incorporated by reference, only if:
(1) You show that complying with the later edition provides a degree
of protection, safety, or performance equal to or better than what would
be achieved by compliance with the listed edition; and
(2) You obtain the prior written approval for alternative compliance
from the authorized BOEM official.
(d) You may inspect these documents at the Bureau of Ocean Energy
Management, 45600 Woodland Road, Sterling, VA 20166, 703-787-1605; or at
the National Archives and Records Administration (NARA). For information
on the availability of this material at NARA, call 202-741-6030, or go
to: http://www.archives.gov/federal_register/
code_of_federal_regulations/ibr_locations.html. You may obtain the
documents from the publishing organizations at the addresses given in
the following table:

------------------------------------------------------------------------
For . . . Write to . . .
------------------------------------------------------------------------
API Recommended Practices.............. American Petroleum Institute,
1220 L Street, NW.,
Washington, DC 20005-4070.
http://www.api.org/
publications/
------------------------------------------------------------------------

[[Page 562]]

(e) This paragraph lists documents incorporated by reference. To
easily reference text of the corresponding sections with the list of
documents incorporated by reference, the list is in alphanumerical order
by organization and document.

----------------------------------------------------------------------------------------------------------------
Title of documents Incorporated by reference at . . .
----------------------------------------------------------------------------------------------------------------
API RP 2A-WSD, Recommended Practice for Planning, 30 CFR 585.825
Designing and Constructing Fixed Offshore
Platforms--Working Stress Design; Twenty-first
Edition, December 2000; Errata and Supplement 1,
December 2002; Errata and Supplement 2, September
2005; Errata and Supplement 3, October 2007;
Product No. G2AWSD.
----------------------------------------------------------------------------------------------------------------

[76 FR 64623, Oct. 18, 2011, as amended at 80 FR 57098, Sept. 22, 2015]

Sec. 585.116 Requests for information on the state of the offshore
renewable energy industry.

(a) The Director may, from time to time, and at his discretion,
solicit information from industry and other relevant stakeholders
(including State and local agencies), as necessary, to evaluate the
state of the offshore renewable energy industry, including the
identification of potential challenges or obstacles to its continued
development. Such requests for information may relate to the
identification of environmental, technical, regulatory, or economic
matters that promote or detract from continued development of renewable
energy technologies on the OCS. From the information received, the
Director may evaluate potential refinements to the OCS Alternative
Energy Program that promote development of the industry in a safe and
environmentally responsible manner, and that ensure fair value for use
of the Nation's OCS.
(b) BOEM may make such requests for information on a regional basis,
and may tailor the requests to specific types of renewable energy
technologies.
(c) BOEM will publish such requests for information by the Director
in the Federal Register.

Sec. 585.117 [Reserved]

Sec. 585.118 What are my appeal rights?

(a) Any party adversely affected by a BOEM official's final decision
or order issued under the regulations of this part may appeal that
decision or order to the Interior Board of Land Appeals. The appeal must
conform with the procedures found in 30 CFR part 590 and 43 CFR part 4,
subpart E. Appeal of a final decision for bid acceptance is covered
under paragraph (c) of this section.
(b) A decision will remain in full force and effect during the
period in which an appeal may be filed and during an appeal, unless a
stay is granted pursuant to 43 CFR part 4.
(c) Our decision on a bid is the final action of the Department,
except that an unsuccessful bidder may apply for reconsideration by the
Director.
(1) A bidder whose bid we reject may file a written request for
reconsideration with the Director within 15 days of the date of the
receipt of the notice of rejection, accompanied by a statement of
reasons, with one copy to us. The Director will respond in writing
either affirming or reversing the decision.
(2) The delegation of review authority given to the Office of
Hearings and Appeals does not apply to decisions on high bids for leases
or grants under this part.

Subpart B_Issuance of OCS Renewable Energy Leases

General Lease Information

Sec. 585.200 What rights are granted with a lease issued under this part?

(a) A lease issued under this part grants the lessee the right,
subject to obtaining the necessary approvals, including but not limited
to those required under the FERC hydrokinetic licensing process, and
complying with all provisions of this part, to occupy, and install and
operate facilities on, a designated portion of the OCS for the purpose
of conducting:
(1) Commercial activities; or

[[Page 563]]

(2) Other limited activities that support, result from, or relate to
the production of energy from a renewable energy source.
(b) A lease issued under this part confers on the lessee the right
to one or more project easements without further competition for the
purpose of installing gathering, transmission, and distribution cables;
pipelines; and appurtenances on the OCS as necessary for the full
enjoyment of the lease.
(1) You must apply for the project easement as part of your COP or
GAP, as provided under subpart F of this part; and
(2) BOEM will incorporate your approved project easement in your
lease as an addendum.
(c) A commercial lease issued under this part may be developed in
phases, with BOEM approval as provided in Sec. 585.629.

Sec. 585.201 How will BOEM issue leases?

BOEM will issue leases on a competitive basis, as provided under
Sec. Sec. 585.210 through 585.225. However, if we determine after
public notice of a proposed lease that there is no competitive interest,
we will issue leases noncompetitively, as provided under Sec. Sec.
585.230 and 585.232. We will issue leases on forms approved by BOEM and
will include terms, conditions, and stipulations identified and
developed through the process set forth in Sec. Sec. 585.211 and
585.231.

Sec. 585.202 What types of leases will BOEM issue?

BOEM may issue leases on the OCS for the assessment and production
of renewable energy and may authorize a combination of specific
activities. We may issue commercial leases or limited leases.

Sec. 585.203 With whom will BOEM consult before issuance of a lease?

For leases issued under this part, through either the competitive or
noncompetitive process, BOEM, prior to issuing the lease, will
coordinate and consult with relevant Federal agencies (including, in
particular, those agencies involved in planning activities that are
undertaken to avoid or minimize conflicts among users and maximize the
economic and ecological benefits of the OCS, including multifaceted
spatial planning efforts), the Governor of any affected State, the
executive of any affected local government, and any affected Indian
Tribe, as directed by subsections 8(p)(4) and (7) of the OCS Lands Act
or other relevant Federal laws. Federal statutes that require BOEM to
consult with interested parties or Federal agencies or to respond to
findings of those agencies, including the Endangered Species Act (ESA)
and the Magnuson-Stevens Fishery Conservation and Management Act (MSA).
BOEM also engages in consultation with state and tribal historic
preservation officers pursuant to the National Historic Preservation Act
(NHPA).

[79 FR 21621, Apr. 17, 2014]

Sec. 585.204 What areas are available for leasing consideration?

BOEM may offer any appropriately platted area of the OCS, as
provided in Sec. 585.205, for a renewable energy lease, except any area
within the exterior boundaries of any unit of the National Park System,
National Wildlife Refuge System, National Marine Sanctuary System, or
any National Monument.

Sec. 585.205 How will leases be mapped?

BOEM will prepare leasing maps and official protraction diagrams of
areas of the OCS. The areas included in each lease will be in accordance
with the appropriate leasing map or official protraction diagram.

Sec. 585.206 What is the lease size?

(a) BOEM will determine the size for each lease based on the area
required to accommodate the anticipated activities. The processes
leading to both competitive and noncompetitive issuance of leases will
provide public notice of the lease size adopted. We will delineate
leases by using mapped OCS blocks or portions, or aggregations of
blocks.
(b) The lease size includes the minimum area that will allow the
lessee sufficient space to develop the project and manage activities in
a manner that is consistent with the provisions of this part. The lease
may include whole lease blocks or portions of a lease block.

[[Page 564]]

Sec. Sec. 585.207-585.209 [Reserved]

Competitive Lease Process

Sec. 585.210 How does BOEM initiate the competitive leasing process?

BOEM may publish in the Federal Register a public notice of Request
for Interest to assess interest in leasing all or part of the OCS for
activities authorized in this part. BOEM will consider information
received in response to a Request for Interest to determine whether
there is competitive interest for scheduling sales and issuing leases.
We may prepare and issue a national, regional, or more specific schedule
of lease sales pertaining to one or more types of renewable energy.

Sec. 585.211 What is the process for competitive issuance of leases?

BOEM will use auctions to award leases on a competitive basis. We
will publish details of the process to be employed for each lease sale
auction in the Federal Register. For each lease sale, we will publish a
Proposed Sale Notice and a Final Sale Notice. Individual lease sales
will include steps such as:
(a) Call for Information and Nominations (Call). BOEM will publish
in the Federal Register Calls for Information and Nominations for
leasing in specified areas. The comment period following issuance of a
Call will be 45 days. In this document, we may:
(1) Request comments on areas which should receive special
consideration and analysis;
(2) Request comments concerning geological conditions (including
bottom hazards); archaeological sites on the seabed or nearshore;
multiple uses of the proposed leasing area (including navigation,
recreation, and fisheries); and other socioeconomic, biological, and
environmental information; and
(3) Suggest areas to be considered by the respondents for leasing.
(b) Area Identification. BOEM will identify areas for environmental
analysis and consideration for leasing. We will do this in consultation
with appropriate Federal agencies, States, local governments, affected
Indian Tribes, and other interested parties.
(1) We may consider for lease those areas nominated in response to
the Call for Information and Nominations, together with other areas that
BOEM determines are appropriate for leasing.
(2) We will evaluate the potential effect of leasing on the human,
marine, and coastal environments, and develop measures to mitigate
adverse impacts, including lease stipulations.
(3) We will consult to develop measures, including lease
stipulations and conditions, to mitigate adverse impacts on the
environment; and
(4) We may hold public hearings on the environmental analysis after
appropriate notice.
(c) Proposed Sale Notice. BOEM will publish the Proposed Sale Notice
in the Federal Register and send it to the Governor of any affected
State, any Indian Tribe that might be affected, and the executive of any
local government that might be affected. The comment period following
issuance of a Proposed Sale Notice will be 60 days.
(d) Final Sale Notice. BOEM will publish the Final Sale Notice in
the Federal Register at least 30 days before the date of the sale.

[76 FR 64623, Oct. 18, 2011, as amended at 79 FR 21621, Apr. 17, 2014]

Sec. 585.212 What is the process BOEM will follow if there is reason
to believe that competitors have withdrawn
before the Final Sale Notice is issued?

BOEM may decide to end the competitive process before the Final Sale
Notice if we have reason to believe that competitors have withdrawn and
competition no longer exists. We will issue a second public notice of
Request for Interest and consider comments received to confirm that
there is no competitive interest.
(a) If, after reviewing comments in response to the notice of
Request for Interest, BOEM determines that there is no competitive
interest in the lease area, and one party wishes to acquire a lease, we
will discontinue the competitive process and will proceed with the
noncompetitive process set forth in Sec. 585.231(d) through (i)
following receipt of the acquisition fee specified in Sec. 585.502(a).

[[Page 565]]

(b) If, after reviewing comments in response to the notice of
Request for Interest, BOEM determines that competitive interest in the
lease area continues to exist, we will continue with the competitive
process set forth in Sec. Sec. 585.211 through 585.225.

[76 FR 64623, Oct. 18, 2011, as amended at 79 FR 21621, Apr. 17, 2014]

Sec. 585.213 What must I submit in response to a Request for Interest
or a Call for Information and Nominations?

If you are a potential lessee, when you respond to a Request for
Interest or a Call, your response must include the following items:
(a) The area of interest for a possible lease.
(b) A general description of your objectives and the facilities that
you would use to achieve those objectives.
(c) A general schedule of proposed activities, including those
leading to commercial operations.
(d) Available and pertinent data and information concerning
renewable energy and environmental conditions in the area of interest,
including energy and resource data and information used to evaluate the
area of interest. BOEM will withhold trade secrets and commercial or
financial information that is privileged or confidential from public
disclosure under exemption 4 of the FOIA and as provided in Sec.
585.113.
(e) Documentation showing that you are qualified to hold a lease, as
specified in Sec. 585.107.
(f) Any other information requested by BOEM in the Federal Register
notice.

Sec. 585.214 What will BOEM do with information
from the Requests for Information or Calls for Information and Nominations?

BOEM will use the information received in response to the Requests
or Calls to:
(a) Identify the lease area;
(b) Develop options for the environmental analysis and leasing
provisions (stipulations, payments, terms, and conditions); and
(c) Prepare appropriate documentation to satisfy applicable Federal
requirements, such as NEPA, CZMA, the ESA, and the MMPA.

Sec. 585.215 What areas will BOEM offer in a lease sale?

BOEM will offer the areas for leasing determined through the process
set forth in Sec. 585.211 of this part. We will not accept nominations
after the Call for Information and Nominations closes.

Sec. 585.216 What information will BOEM publish in the Proposed Sale Notice
and Final Sale Notice?

For each competitive lease sale, BOEM will publish a Proposed Sale
Notice and a Final Sale Notice in the Federal Register. In the Proposed
Sale Notice, we will request public comment on the items listed in this
section. We will consider all public comments received in developing the
final lease sale terms and conditions. We will publish the final terms
and conditions in the Final Sale Notice. The Proposed Sale Notice and
Final Sale Notice will include, or describe the availability of,
information pertaining to:
(a) The area available for leasing.
(b) Proposed and final lease provisions and conditions, including,
but not limited to:
(1) Lease size;
(2) Lease term;
(3) Payment requirements;
(4) Performance requirements; and
(5) Site-specific lease stipulations.
(c) Auction details, including:
(1) Bidding procedures and systems;
(2) Minimum bid;
(3) Deposit amount;
(4) The place and time for filing bids and the place, date, and hour
for opening bids;
(5) Lease award method; and
(6) Bidding or application instructions.
(d) The official BOEM lease form to be used or a reference to that
form.
(e) Criteria BOEM will use to evaluate competing bids or
applications and how the criteria will be used in decision-making for
awarding a lease.
(f) Award procedures, including how and when BOEM will award leases
and how BOEM will handle unsuccessful bids or applications.

[[Page 566]]

(g) Procedures for appealing the lease issuance decision.
(h) Execution of the lease instrument.

Sec. Sec. 585.217-585.219 [Reserved]

Competitive Lease Award Process

Sec. 585.220 What auction format may BOEM use in a lease sale?

(a) Except as provided in Sec. 585.231, we will hold competitive
auctions to award renewable energy leases and will use one of the
following auction formats, as determined through the lease sale process
and specified in the Proposed Sale Notice and in the Final Sale Notice:

------------------------------------------------------------------------
Type of auction Bid variable Bidding process
------------------------------------------------------------------------
(1) Sealed bidding.......... A cash bonus or an One sealed bid per
operating fee rate. company per lease
or packaged bidding
unit.
(2) Ascending bidding....... A cash bonus or an Continuous bidding
operating fee rate. per lease.
(3) Two-stage bidding An operating fee Ascending or sealed
(combination of ascending rate in one, both, bidding until:
and sealed bidding). or neither stage (i) Only two bidders
and a cash bonus in remain, or
one, both, or (ii) More than one
neither stage. bidder offers to
pay the maximum bid
amount.
Stage-two sealed or
ascending bidding
commences at some
predetermined time
after the end of
stage-one bidding.
(4) Multiple-factor bidding. Factors may include, One proposal per
but are not limited company per lease
to: technical or packaged bidding
merit, timeliness, unit.
financing and
economics,
environmental
considerations,
public benefits,
compatibility with
State and local
needs, cash bonus,
rental rate, and an
operating fee rate.
------------------------------------------------------------------------

(b) You must submit your bid and a deposit as specified in
Sec. Sec. 585.500 and 585.501 to cover the bid for each lease area,
according to the terms specified in the Final Sale Notice.

Sec. 585.221 What bidding systems may BOEM use for commercial leases
and limited leases?

(a) For commercial leases, we will specify minimum bids in the Final
Sale Notice and use one of the following bidding systems, as specified
in the Proposed Sale Notice and in the Final Sale Notice:

------------------------------------------------------------------------
Bid system Bid variable
------------------------------------------------------------------------
(1) Cash bonus with a constant fee rate Cash bonus.
(decimal).
(2) Constant operating fee rate with A fee rate used in the formula
fixed cash bonus. found in Sec. 585.506 to set
the operating fee per year
during the operations term of
your lease.
(3) Sliding operating fee rate with a A fee rate used in the formula
fixed cash bonus. in Sec. 585.506 to set the
operating fee for the first
year of the operations term of
your lease. The fee rate for
subsequent years changes by a
mathematical function we
specify in the Final Sale
Notice.
(4) Cash bonus and constant operating Cash bonus and operating fee
fee rate. rate as stated in paragraph
(2) of this section (two-stage
auction format only).
(5) Cash bonus and sliding operating Cash bonus and operating fee
fee rate. rate as stated in paragraph
(3) of this section (two-stage
auction format only).
(6) Multiple-factor combination of BOEM will identify bidding
nonmonetary and monetary factors. variables in the Final Sale
Notice.
Variables may include:
(i) Nonmonetary (e.g.,
technical merit) factors and
(ii) Monetary (e.g., cash
bonus, rental rate, fee rate)
factors.
------------------------------------------------------------------------

[[Page 567]]

(b) For limited leases, the bid variable will be a cash bonus, with
a minimum bid as we specify in the Final Sale Notice.

Sec. 585.222 What does BOEM do with my bid?

(a) If sealed bidding is used:
(1) We open the sealed bids at the place, date, and hour specified
in the Final Sale Notice for the sole purpose of publicly announcing and
recording the bids. We do not accept or reject any bids at that time.
(2) We reserve the right to reject any and all high bids, including
a bid for any proposal submitted under the multiple-factor bidding
format, regardless of the amount offered or bidding system used. The
reasons for the rejection of a winning bid may include, but are not
necessarily limited to, insufficiency, illegality, anti-competitive
behavior, administrative error, and the presence of unusual bidding
patterns. We intend to accept or reject all high bids within 90 days,
but we may extend that time if necessary.
(b) If we use ascending bidding, we may, in the Final Sale Notice,
reserve the right to accept the winning bid solely based on its being
the highest bid submitted by a qualified bidder (qualified to be an OCS
lessee under Sec. 585.107).
(c) If we use two-stage bidding and the auction concludes with
(i) An ascending bidding stage, the winning bid will be determined
as stated in paragraph (b) of this section; or
(ii) A sealed bidding stage, the winning bid will be determined as
stated in paragraph (a) of this section.
(d) If we use multiple-factor bidding, determination of the winning
bid for any proposal submitted will be made by a panel composed of
members selected by BOEM. The details of the process will be described
in the Final Sale Notice.
(e) We will send a written notice of our decision to accept or
reject bids to all bidders whose deposits we hold.

Sec. 585.223 What does BOEM do if there is a tie for the highest bid?

(a) Unless otherwise specified in the Final Sale Notice, except in
the first stage of a two-stage bidding auction, if more than one bidder
on a lease submits the same high bid amount, the winning bidder will be
determined by a further round or stage of bidding as described in the
Final Sale Notice.
(b) The winning bidder will be subject to final confirmation
following determination of bid adequacy.

Sec. 585.224 What happens if BOEM accepts my bid?

If we accept your bid, we will send you a notice with three copies
of the lease form.
(a) Within 10 business days after you receive the lease copies, you
must:
(1) Execute the lease;
(2) File financial assurance as required under Sec. Sec. 585.515
through 585.537; and
(3) Pay the balance of the bonus bid as specified in the lease sale
notice.
(b) Within 45 days after you receive the lease copies, you must pay
the first 12-months' rent as required in Sec. 585.503.
(c) When you execute three copies of the lease and return the copies
to us, we will execute the lease on behalf of the United States and send
you one fully executed copy.
(d) You will forfeit your deposit if you do not execute and return
the lease within 10 business days of receipt, or otherwise fail to
comply with applicable regulations or terms of the Final Sale Notice.
(e) We may extend the 10 business day time period for executing and
returning the lease if we determine the delay to be caused by events
beyond your control.
(f) We reserve the right to withdraw an OCS area in which we have
held a lease sale before you and BOEM execute the lease in that area. If
we exercise this right, we will refund your bid deposit, without
interest.
(g) If the awarded lease is executed by an agent acting on behalf of
the bidder, the bidder must submit, along with the executed lease,
written evidence that the agent is authorized to act on behalf of the
bidder.
(h) BOEM will consider the highest submitted qualified bid to be the
winning bid when bidding occurs under the systems described in Sec.
585.221(a)(1) through (5). We will determine the winning bid for
proposals submitted under

[[Page 568]]

the multiple-factor bidding format on the basis of selection by the
panel as specified in Sec. 585.222(d) when the bidding system under
Sec. 585.221(a)(6) is used. We will refund the deposit on all other
bids.

[76 FR 64623, Oct. 18, 2011, as amended at 79 FR 21621, Apr. 17, 2014]

Sec. 585.225 What happens if my bid is rejected,
and what are my appeal rights?

(a) If we reject your bid, we will provide a written statement of
the reasons and refund any money deposited with your bid, without
interest.
(b) You may ask the BOEM Director for reconsideration, in writing,
within 15 business days of bid rejection, under Sec. 585.118(c)(1). We
will send you a written response either affirming or reversing the
rejection.

Sec. Sec. 585.226-585.229 [Reserved]

Noncompetitive Lease Award Process

Sec. 585.230 May I request a lease if there is no Call?

You may submit an unsolicited request for a commercial lease or a
limited lease under this part. Your unsolicited request must contain the
following information:
(a) The area you are requesting for lease.
(b) A general description of your objectives and the facilities that
you would use to achieve those objectives.
(c) A general schedule of proposed activities including those
leading to commercial operations.
(d) Available and pertinent data and information concerning
renewable energy and environmental conditions in the area of interest,
including energy and resource data and information used to evaluate the
area of interest. BOEM will withhold trade secrets and commercial or
financial information that is privileged or confidential from public
disclosure under exemption 4 of the FOIA and as provided in Sec.
585.113.
(e) If available from the appropriate State or local government
authority, a statement that the proposed activity conforms with State
and local energy planning requirements, initiatives, or guidance.
(f) Documentation showing that you meet the qualifications to become
a lessee, as specified in Sec. 585.107.
(g) An acquisition fee, as specified in Sec. 585.502(a).

Sec. 585.231 How will BOEM process my unsolicited request
for a noncompetitive lease?

(a) BOEM will consider unsolicited requests for a lease on a case-
by-case basis and may issue a lease noncompetitively in accordance with
this part. We will not consider an unsolicited request for a lease under
this part that is proposed in an area of the OCS that is scheduled for a
lease sale under this part.
(b) BOEM will issue a public notice of a request for interest
relating to your proposal and consider comments received to determine if
competitive interest exists.
(c) If BOEM determines that competitive interest exists in the lease
area:
(1) BOEM will proceed with the competitive process set forth in
Sec. Sec. 585.210 through 585.225;
(2) If you submit a bid for the lease area in a competitive lease
sale, your acquisition fee will be applied to the deposit for your bonus
bid; and
(3) If you do not submit a bid for the lease area in a competitive
lease sale, BOEM will not refund your acquisition fee.
(d) If BOEM determines that there is no competitive interest in a
lease, we will publish in the Federal Register a notice of Determination
of No Competitive Interest. After BOEM publishes this notice, you will
be responsible for submitting any required consistency certification and
necessary data and information pursuant to 15 CFR part 930, subpart D to
the applicable State CZMA agency or agencies and BOEM.
(e) BOEM will coordinate and consult with affected Federal agencies,
State, and local governments, and affected Indian tribes in the review
of noncompetitive lease requests.
(f) After completing the review of your lease request, BOEM may
offer you a noncompetitive lease.
(g) If you accept the terms and conditions of the lease, then we
will issue

[[Page 569]]

the lease, and you must comply with all terms and conditions of your
lease and all applicable provisions of this part. If we issue you a
lease, we will send you a notice with 3 copies of the lease form.
(1) Within 10 business days after you receive the lease copies you
must:
(i) Execute the lease;
(ii) File financial assurance as required under Sec. Sec. 585.515
through 585.537; and
(2) Within 45 days after you receive the lease copies, you must pay
the first 12-months' rent, as required in Sec. 585.503.
(h) BOEM will publish in the Federal Register a notice announcing
the issuance of your lease.
(i) If you do not accept the terms and conditions, BOEM will not
issue a lease, and we will not refund your acquisition fee.

[76 FR 64623, Oct. 18, 2011, as amended at 77 FR 1019, Jan. 9, 2012; 79
FR 21622, Apr. 17, 2014]

Sec. 585.232 May I acquire a lease noncompetitively after responding
to a Request for Interest or Call for Information and Nominations?

(a) If you submit an area of interest for a possible lease and BOEM
receives no competing submissions in response to the RFI or Call, we may
inform you that there does not appear to be competitive interest, and
ask if you wish to proceed with acquiring a lease.
(b) If you wish to proceed with acquiring a lease, you must submit
your acquisition fee as specified in Sec. 585.502(a).
(c) After receiving the acquisition fee, BOEM will follow the
process outlined in Sec. 585.231(d) through (i).

[76 FR 64623, Oct. 18, 2011, as amended at 77 FR 1019, Jan. 9, 2012]

Sec. Sec. 585.233-585.234 [Reserved]

Commercial and Limited Lease Terms

Sec. 585.235 If I have a commercial lease, how long will my lease
remain in effect?

(a) For commercial leases, the lease terms and applicable automatic
extensions are as shown in the following table:

------------------------------------------------------------------------
Lease term Automatic extensions Requirements
------------------------------------------------------------------------
(1) Each commercial lease If BOEM receives a The SAP must meet
will have a preliminary SAP that satisfies the requirements of
term of 12 months, within the requirements of Sec. Sec.
which the lessee must Sec. Sec. 585.605 through
submit: (i) a SAP; or (ii) 585.605 through 585.613. The SAP/
a combined SAP and 585.613 or a SAP/ COP must meet the
Construction and Operations COP that satisfies requirements of
Plan (COP). The preliminary the requirements of Sec. Sec.
term begins on the Sec. Sec. 585.605 through
effective date of the lease. 585.605 through 585.613 and Sec.
585.613 and Sec. Sec. 585.620
Sec. 585.620 through 585.629.
through 585.629,
the preliminary
term will be
extended for the
time necessary for
us to conduct
technical and
environmental
reviews of the SAP
or SAP/COP.
(2) A commercial lease will If we receive a COP The COP must meet
have a site assessment term that satisfies the the requirements of
of five years to conduct requirements of Sec. Sec.
site assessment activities Sec. Sec. 585.620 through
and to submit a COP, if a 585.620 through 585.629 of this
SAP/COP has not been 585.629, the site part.
submitted. Your site assessment term
assessment term begins when will be
BOEM approves your SAP or automatically
SAP/COP. extended for the
period of time
necessary for us to
conduct technical
and environmental
reviews of the COP.
(3) A commercial lease will .................... The lease renewal
have an operations term of request must meet
25 years, unless a longer the requirements in
term is negotiated by the Sec. Sec.
parties. A request for 585.425 through
lease renewal must be 585.429.
submitted two years before
the end of the operations
term. If you submit a COP,
your operations term begins
on the date that BOEM
approves the COP. If you
submit a SAP/COP, your
operations term begins on
the earliest of the
following dates: five years
after BOEM approves the SAP/
COP; when fabrication
begins; or, when
installation commences.

[[Page 570]]

(4) A commercial lease may .................... NOTE: BOEM may also
have additional time added order or grant a
to the operations term suspension of the
through a lease renewal. operations term, as
The term of the lease provided in Sec.
renewal will not exceed the Sec. 585.415
original term of the lease, through 585.421
unless a longer term is thereby effectively
negotiated by the parties. extending the term
The lease renewal term of the lease.
begins upon expiration of
the original operations
term.
------------------------------------------------------------------------

(b) If you do not timely submit a SAP, COP, or SAP/COP, as
appropriate, you may request additional time to extend the preliminary
or site assessment term of your commercial lease that includes a revised
schedule for submission of the plan, as appropriate.

[76 FR 64623, Oct. 18, 2011, as amended at 79 FR 21622, Apr. 17, 2014]

Sec. 585.236 If I have a limited lease, how long will my lease
remain in effect?

(a) For limited leases, the lease terms are as shown in the
following table:

------------------------------------------------------------------------
Extension or
Lease term suspension Requirements
------------------------------------------------------------------------
(1) Each limited lease has a If we receive a GAP The GAP must meet
preliminary term of 12 that satisfies the the requirements of
months to submit a GAP. The requirements of Sec. Sec.
preliminary term begins on Sec. Sec. 585.640 through
the effective date of the 585.640 through 585.648.
lease. 585.648 of this
part, the
preliminary term
will be
automatically
extended for the
period of time
necessary for us to
conduct a technical
and environmental
review of the plans.
(2) Each limited lease has We may order or
an operations term of five grant a suspension
years for conducting site of the operations
assessment, technology term as provided in
testing, or other Sec. Sec.
activities. The operations 585.415 through
term begins on the date 585.421.
that we approve your GAP.
------------------------------------------------------------------------

(b) If you do not timely submit a GAP, you may request additional
time to extend the preliminary term of your limited lease that includes
a revised schedule for submission of a GAP.

[76 FR 64623, Oct. 18, 2011, as amended at 79 FR 21622, Apr. 17, 2014]

Sec. 585.237 What is the effective date of a lease?

(a) A lease issued under this part must be dated and becomes
effective as of the first day of the month following the date a lease is
signed by the lessor.
(b) If the lessee submits a written request and BOEM approves, a
lease may be dated and become effective the first day of the month in
which it is signed by the lessor.

Sec. 585.238 Are there any other renewable energy research activities
that will be allowed on the OCS?

(a) The Director may issue OCS leases, ROW grants, and RUE grants to
a Federal agency or a State for renewable energy research activities
that support the future production, transportation, or transmission of
renewable energy.
(b) In issuing leases, ROW grants, and RUE grants to a Federal
agency or a State on the OCS for renewable energy research activities
under this provision, BOEM will coordinate and consult with other
relevant Federal agencies, any other affected State(s), affected local
government executives, and affected Indian Tribes.
(c) BOEM may issue leases, RUEs, and ROWs for research activities
managed by a Federal agency or a State only in areas for which the
Director

[[Page 571]]

has determined, after public notice and opportunity to comment, that no
competitive interest exists.
(d) The Director and the head of the Federal agency or the Governor
of a requesting State, or their authorized representatives, will
negotiate the terms and conditions of such renewable energy leases,
RUEs, or ROWs under this provision on a case-by-case basis. The
framework for such negotiations, and standard terms and conditions of
such leases, RUEs, or ROWs may be set forth in a memorandum of agreement
(MOA) or other agreement between BOEM and a Federal agency or a State.
The MOA must include the agreement of the head of the Federal agency or
the Governor to assure that all subcontractors comply with these
regulations, other applicable laws, and terms and conditions of such
leases or grants.
(e) Any lease, RUE, or ROW that BOEM issues to a Federal agency or
to a State that authorizes access to an area of the OCS for research
activities managed by a Federal agency or a State must include:
(1) Requirements to comply with all applicable Federal laws; and
(2) Requirements to comply with these regulations, except as
otherwise provided in the lease or grant.
(f) BOEM will issue a public notice of any lease, RUE, ROW issued to
a Federal agency or to a State, or an approved MOA for such research
activities.
(g) BOEM will not charge any fees for the purpose of ensuring a fair
return for the use of such research areas on the OCS.

Subpart C_Rights-of-Way Grants and Rights-of-Use and Easement Grants for
Renewable Energy Activities

ROW Grants and RUE Grants

Sec. 585.300 What types of activities are authorized by ROW grants
and RUE grants issued under this part?

(a) An ROW grant authorizes the holder to install on the OCS cables,
pipelines, and associated facilities that involve the transportation or
transmission of electricity or other energy product from renewable
energy projects.
(b) An RUE grant authorizes the holder to construct and maintain
facilities or other installations on the OCS that support the
production, transportation, or transmission of electricity or other
energy product from any renewable energy resource.
(c) You do not need an ROW grant or RUE grant for a project easement
authorized under Sec. 585.200(b) to serve your lease.

Sec. 585.301 What do ROW grants and RUE grants include?

(a) An ROW grant:
(1) Includes the full length of the corridor on which a cable,
pipeline, or associated facility is located;
(2) Is 200 feet (61 meters) in width, centered on the cable or
pipeline, unless safety and environmental factors during construction
and maintenance of the associated cable or pipeline require a greater
width; and
(3) For the associated facility, is limited to the area reasonably
necessary for a power or pumping station or other accessory facility.
(b) An RUE grant includes the site on which a facility or other
structure is located and the areal extent of anchors, chains, and other
equipment associated with a facility or other structure. The specific
boundaries of an RUE will be determined by BOEM on a case-by-case basis
and set forth in each RUE grant.

Sec. 585.302 What are the general requirements for ROW grant
and RUE grant holders?

(a) To acquire an ROW grant or RUE grant you must provide evidence
that you meet the qualifications as required in Sec. 585.107.
(b) An ROW grant or RUE grant is subject to the following
conditions:
(1) The rights granted will not prevent the granting of other rights
by the United States, either before or after the granting of the ROW or
RUE, provided that any subsequent authorization issued by BOEM in the
area of a previously issued ROW grant or RUE grant may not unreasonably
interfere

[[Page 572]]

with activities approved or impede existing operations under such a
grant; and
(2) The holder agrees that the United States, its lessees, or other
ROW grant or RUE grant holders may use or occupy any part of the ROW
grant or RUE grant not actually occupied or necessarily incident to its
use for any necessary activities.

Sec. 585.303 How long will my ROW grant or RUE grant remain in effect?

(a) Each ROW or RUE grant will have a preliminary term of 12 months
from the date of issuance of the ROW or RUE grant within which to submit
a GAP. The preliminary term begins on the effective date of the grant.
You must submit a GAP no later than the end of the preliminary term for
your grant to remain in effect. However, you may submit a GAP prior to
the issuance of your ROW or RUE grant.
(b) Except as described in paragraph (a) of this section, your ROW
grant or RUE grant will remain in effect for as long as the associated
activities are properly maintained and used for the purpose for which
the grant was made, unless otherwise expressly stated in the grant.

[79 FR 21623, Apr. 17, 2014]

Sec. 585.304 [Reserved]

Obtaining ROW Grants and RUE Grants

Sec. 585.305 How do I request an ROW grant or RUE grant?

You must submit to BOEM one paper copy and one electronic copy of a
request for a new or modified ROW grant or RUE grant. You must submit a
separate request for each ROW grant or RUE grant you are requesting. The
request must contain the following information:
(a) The area you are requesting for a ROW grant or RUE grant.
(b) A general description of your objectives and the facilities that
you would use to achieve those objectives.
(c) A general schedule of proposed activities.
(d) Pertinent information concerning environmental conditions in the
area of interest.

Sec. 585.306 What action will BOEM take on my request?

BOEM will consider requests for ROW grants and RUE grants on a case-
by-case basis and may issue a grant competitively, as provided in Sec.
585.308, or noncompetitively if we determine after public notice that
there is no competitive interest. BOEM will coordinate and consult with
relevant Federal agencies, with the Governor of any affected State, and
the executive of any affected local government.
(a) In response to an unsolicited request for a ROW grant or RUE
grant, the BOEM will first determine if there is competitive interest,
as provided in Sec. 585.307.
(b) If BOEM determines that there is no competitive interest in a
ROW grant or RUE grant, we will publish a notice in the Federal Register
of such determination. After BOEM publishes this notice, you will be
responsible for submitting any required consistency certification and
necessary data and information pursuant to 15 CFR part 930, subpart D to
the applicable State CZMA agency or agencies and BOEM. We will establish
terms and conditions for the grant in consultation with you.

[76 FR 64623, Oct. 18, 2011, as amended at 79 FR 21623, Apr. 17, 2014]

Sec. 585.307 How will BOEM determine whether competitive interest exists
for ROW grants and RUE grants?

To determine whether or not there is competitive interest:
(a) We will publish a public notice, describing the parameters of
the project, to give affected and interested parties an opportunity to
comment on the proposed ROW grant or RUE grant area.
(b) We will evaluate any comments received on the notice and make a
determination of the level of competitive interest.

Sec. 585.308 How will BOEM conduct an auction for ROW grants and RUE grants?

(a) If BOEM determines that there is competitive interest, we will:
(1) Publish a notice of each grant auction in the Federal Register
describing auction procedures, allowing

[[Page 573]]

interested persons 30 days to comment; and
(2) Conduct a competitive auction for issuing the ROW grant or RUE
grant. The auction process for ROW grants and RUE grants will be
conducted following the same process for leases set forth in Sec. Sec.
585.211 through 585.225.
(b) If you are the successful bidder in an auction, you must pay the
first year's rent, as provided in Sec. 585.316.

Sec. 585.309 When will BOEM issue a noncompetitive ROW grant or RUE grant?

After completing the review of your grant request, BOEM may offer
you a noncompetitive grant.
(a) If you accept the terms and conditions of the grant, then we
will issue the grant, and you must comply with all terms and conditions
of your grant and all applicable provisions of this part.
(b) If you do not accept the terms and conditions, BOEM will not
issue a grant.

[76 FR 64623, Oct. 18, 2011, as amended at 79 FR 21623, Apr. 17, 2014]

Sec. 585.310 What is the effective date of an ROW grant or RUE grant?

Your ROW grant or RUE grant becomes effective on the date
established by BOEM on the ROW grant or RUE grant instrument.

Sec. Sec. 585.311-585.314 [Reserved]

Financial Requirements for ROW Grants and RUE Grants

Sec. 585.315 What deposits are required for a competitive ROW grant
or RUE grant?

(a) You must make a deposit, as required in Sec. 585.501(a),
regardless of whether the auction is a sealed-bid, oral, electronic, or
other auction format. BOEM will specify in the sale notice the official
to whom you must submit the payment, the time by which the official must
receive the payment, and the forms of acceptable payment.
(b) If your high bid is rejected, we will provide a written
statement of reasons.
(c) For all rejected bids, we will refund, without interest, any
money deposited with your bid.

Sec. 585.316 What payments are required for ROW grants or RUE grants?

Before we issue the ROW grant or RUE grant, you must pay:
(a) Any balance on accepted high bids to BOEM, as provided in the
sale notice.
(b) An annual rent for the first year of the grant, as specified in
Sec. 585.508.

Subpart D_Lease and Grant Administration

Noncompliance and Cessation Orders

Sec. 585.400 What happens if I fail to comply with this part?

(a) BOEM may take appropriate corrective action under this part if
you fail to comply with applicable provisions of Federal law, the
regulations in this part, other applicable regulations, any order of the
Director, the provisions of a lease or grant issued under this part, or
the requirements of an approved plan or other approval under this part.
(b) BOEM may issue to you a notice of noncompliance if we determine
that there has been a violation of the regulations in this part, any
order of the Director, or any provision of your lease, grant or other
approval issued under this part. When issuing a notice of noncompliance,
BOEM will serve you at your last known address.
(c) A notice of noncompliance will tell you how you failed to comply
with this part, any order of the Director, and/or the provisions of your
lease, grant or other approval, and will specify what you must do to
correct the noncompliance and the time limits within which you must act.
(d) Failure of a lessee, operator, or grant holder under this part
to take the actions specified in a notice of noncompliance within the
time limit specified provides the basis for BOEM to issue a cessation
order as provided in Sec. 585.401, and/or a cancellation of the lease
or grant as provided in Sec. 585.437.
(e) If BOEM determines that any incident of noncompliance poses an
imminent threat of serious or irreparable damage to natural resources;
life (including human and wildlife); property; the marine, coastal, or
human environment; or sites, structures, or objects of

[[Page 574]]

historical or archaeological significance, BOEM may include with its
notice of noncompliance an order directing you to take immediate
remedial action to alleviate threats and to abate the violation and,
when appropriate, a cessation order.
(f) The BOEM may assess civil penalties, as authorized by section 24
of the OCS Lands Act, if you fail to comply with any provision of this
part or any term of a lease, grant, or order issued under the authority
of this part, after notice of such failure and expiration of any
reasonable period allowed for corrective action. Civil penalties will be
determined and assessed in accordance with the procedures set forth in
30 CFR part 550, subpart N.
(g) You may be subject to criminal penalties as authorized by
section 24 of the OCS Lands Act.

Sec. 585.401 When may BOEM issue a cessation order?

(a) BOEM may issue a cessation order during the term of your lease
or grant when you fail to comply with an applicable law; regulation;
order; or provision of a lease, grant, plan, or other BOEM approval
under this part. Except as provided in Sec. 585.400(e), BOEM will allow
you a period of time to correct any noncompliance before issuing an
order to cease activities.
(b) A cessation order will set forth what measures you are required
to take, including reports you are required to prepare and submit to
BOEM, to receive approval to resume activities on your lease or grant.

Sec. 585.402 What is the effect of a cessation order?

(a) Upon receiving a cessation order, you must cease all activities
on your lease or grant, as specified in the order. BOEM may authorize
certain activities during the period of the cessation order.
(b) A cessation order will last for the period specified in the
order or as otherwise specified by BOEM. If BOEM determines that the
circumstances giving rise to the cessation order cannot be resolved
within a reasonable time period, the Secretary may initiate cancellation
of your lease or grant, as provided in Sec. 585.437.
(c) A cessation order does not extend the term of your lease or
grant for the period you are prohibited from conducting activities.
(d) You must continue to make all required payments on your lease or
grant during the period a cessation order is in effect.

Sec. Sec. 585.403-585.404 [Reserved]

Designation of Operator

Sec. 585.405 How do I designate an operator?

(a) If you intend to designate an operator who is not the lessee or
grant holder, you must identify the proposed operator in your SAP (under
Sec. 585.610(a)(3)), COP (under Sec. 585.626(b)(2)), or GAP (under
Sec. 585.645(b)(3)), as applicable. If no operator is designated in a
SAP, COP, or GAP, BOEM will deem the lessee or grant holder to be the
operator.
(b) An operator must be designated in any SAP, COP, or GAP if there
is more than one lessee or grant holder for any individual lease or
grant.
(c) Once approved in your plan, the designated operator is
authorized to act on your behalf and required to perform activities
necessary to comply with the OCS Lands Act, the lease or grant, and the
regulations in this part.
(d) You, or your designated operator, must immediately provide BOEM
with a written notification of change of address of the lessee or
operator.
(e) If there is a change in the designated operator, you must
provide written notice to BOEM and identify the new designated operator
within 72 hours on a form approved by BOEM. The lessee(s) or grantee(s)
is the operator and responsible for compliance until BOEM approves
designation of the new operator.
(f) Designation of an operator under any lease or grant issued under
this part does not relieve the lessee or grant holder of its obligations
under this part or its lease or grant.
(g) A designated operator performing activities on the lease must
comply with all regulations governing those activities and may be held
liable or penalized for any noncompliance during the time it was
operator, notwithstanding its subsequent resignation.

[[Page 575]]

Sec. 585.406 Who is responsible for fulfilling lease and grant obligations?

(a) When you are not the sole lessee or grantee, you and your co-
lessee(s) or co-grantee(s) are jointly and severally responsible for
fulfilling your obligations under the lease or grant and the provisions
of this part, unless otherwise provided in these regulations.
(b) If your designated operator fails to fulfill any of your
obligations under the lease or grant and this part, BOEM may require you
or any or all of your co-lessees or co-grantees to fulfill those
obligations or other operational obligations under the OCS Lands Act,
the lease, grant, or the regulations.
(c) Whenever the regulations in this part require the lessee or
grantee to conduct an activity in a prescribed manner, the lessee or
grantee and operator (if one has been designated) are jointly and
severally responsible for complying with the regulations.

Sec. 585.407 [Reserved]

Lease or Grant Assignment

Sec. 585.408 May I assign my lease or grant interest?

(a) You may assign all or part of your lease or grant interest,
including record title, subject to BOEM approval under this subpart.
Each instrument that creates or transfers an interest must describe the
entire tract or describe by officially designated subdivisions the
interest you propose to create or transfer.
(b) You may assign a lease or grant interest by submitting one paper
copy and one electronic copy of an assignment application to BOEM. The
assignment application must include:
(1) BOEM-assigned lease or grant number;
(2) A description of the geographic area or undivided interest you
are assigning;
(3) The names of both the assignor and the assignee, if applicable;
(4) The names and telephone numbers of the contacts for both the
assignor and the assignee;
(5) The names, titles, and signatures of the authorizing officials
for both the assignor and the assignee;
(6) A statement that the assignee agrees to comply with and to be
bound by the terms and conditions of the lease or grant;
(7) The qualifications of the assignee to hold a lease or grant
under Sec. 585.107; and
(8) A statement on how the assignee will comply with the financial
assurance requirements of Sec. Sec. 585.515 through 585.537. No
assignment will be approved until the assignee provides the required
financial assurance.
(c) If you submit an application to assign a lease or grant, you
will continue to be responsible for payments that are or become due on
the lease or grant until the date BOEM approves the assignment.
(d) The assignment takes effect on the date BOEM approves your
application.
(e) You do not need to request an assignment for mergers, name
changes, or changes of business form. You must notify BOEM of these
events under Sec. 585.109.

Sec. 585.409 How do I request approval of a lease or grant assignment?

(a) You must request approval of each assignment on a form approved
by BOEM, and submit originals of each instrument that creates or
transfers ownership of record title or certified copies thereof within
90 days after the last party executes the transfer agreement.
(b) Any assignee will be subject to all the terms and conditions of
your original lease or grant, including the requirement to furnish
financial assurance in the amount required in Sec. Sec. 585.515 through
585.537.
(c) The assignee must submit proof of eligibility and other
qualifications specified in Sec. 585.107.
(d) Persons executing on behalf of the assignor and assignee must
furnish evidence of authority to execute the assignment.

Sec. 585.410 How does an assignment affect the assignor's liability?

As assignor, you are liable for all obligations, monetary and
nonmonetary, that accrued under your lease or grant before BOEM approves
your assignment. Our approval of the assignment

[[Page 576]]

does not relieve you of these accrued obligations. BOEM may require you
to bring the lease or grant into compliance to the extent the obligation
accrued before the effective date of your assignment if your assignee or
subsequent assignees fail to perform any obligation under the lease or
grant.

Sec. 585.411 How does an assignment affect the assignee's liability?

(a) As assignee, you are liable for all lease or grant obligations
that accrue after BOEM approves the assignment. As assignee, you must
comply with all the terms and conditions of the lease or grant and all
applicable regulations, remedy all existing environmental and
operational problems on the lease or grant, and comply with all
decommissioning requirements under subpart I of this part.
(b) Assignees are bound to comply with each term or condition of the
lease or grant and the regulations in this subchapter. You are jointly
and severally liable for the performance of all obligations under the
lease or grant and under the regulations in this part with each prior
and subsequent lessee who held an interest from the time the obligation
accrued until it is satisfied, unless this part provides otherwise.

Sec. Sec. 585.412-585.414 [Reserved]

Lease or Grant Suspension

Sec. 585.415 What is a lease or grant suspension?

(a) A suspension is an interruption of the term of your lease or
grant that may occur:
(1) As approved by BOEM at your request, as provided in Sec.
585.416; or
(2) As ordered by BOEM, as provided in Sec. 585.417.
(b) A suspension extends the term of your lease or grant for the
length of time the suspension is in effect.
(c) Activities may not be conducted on your lease or grant during
the period of a suspension except as expressly authorized by BOEM under
the terms of the suspension.

Sec. 585.416 How do I request a lease or grant suspension?

You must submit a written request to BOEM that includes the
following information no later than 90 days prior to the expiration of
your appropriate lease or grant term:
(a) The reasons you are requesting suspension of your lease or grant
term, and the length of additional time requested.
(b) An explanation of why the suspension is necessary in order to
ensure full enjoyment of your lease or grant and why it is in the
lessor's or grantor's interest to approve the suspension.
(c) If you do not timely submit a SAP, COP, or GAP, as required, you
may request a suspension to extend the preliminary or site assessment
term of your lease or grant that includes a revised schedule for
submission of a SAP, COP, or GAP, as appropriate.
(d) Any other information BOEM may require.

Sec. 585.417 When may BOEM order a suspension?

(a) BOEM may order a suspension under the following circumstances:
(1) When necessary to comply with judicial decrees prohibiting some
or all activities under your lease;
(2) When continued activities pose an imminent threat of serious or
irreparable harm or damage to natural resources; life (including human
and wildlife); property; the marine, coastal, or human environment; or
sites, structures, or objects of historical or archaeological
significance; or
(3) When the suspension is necessary for reasons of National
security or defense.
(b) If BOEM orders a suspension under paragraph (a)(2) of this
section, and if you wish to resume activities, we may require you to
conduct a site-specific study that evaluates the cause of the harm, the
potential damage, and the available mitigation measures. Other
requirements and actions may occur:
(1) You may be required to pay for the study;
(2) You must furnish one paper copy and one electronic copy of the
study and results to us;
(3) We will make the results available to other interested parties
and to the public; and

[[Page 577]]

(4) We will use the results of the study and any other information
that become available:
(i) To decide if the suspension order can be lifted; and
(ii) To determine any actions that you must take to mitigate or
avoid any damage to natural resources; life (including human and
wildlife); property; the marine, coastal, or human environment; or
sites, structures, or objects of historical or archaeological
significance.

Sec. 585.418 How will BOEM issue a suspension?

(a) BOEM will issue a suspension order orally or in writing.
(b) BOEM will send you a written suspension order as soon as
practicable after issuing an oral suspension order.
(c) The written order will explain the reasons for its issuance and
describe the effect of the suspension order on your lease or grant and
any associated activities. BOEM may authorize certain activities during
the period of the suspension, as set forth in the suspension order.

Sec. 585.419 What are my immediate responsibilities
if I receive a suspension order?

You must comply with the terms of a suspension order upon receipt
and take any action prescribed within the time set forth therein.

Sec. 585.420 What effect does a suspension order have on my payments?

(a) While BOEM evaluates your request for a suspension under Sec.
585.416, you must continue to fulfill your payment obligation until the
end of the original term of your lease or grant. If our evaluation goes
beyond the end of the original term of your lease or grant, the term of
your lease or grant will be extended for the period of time necessary
for BOEM to complete its evaluation of your request, but you will not be
required to make payments during the time of the extension.
(b) If BOEM approves your request for a suspension, as provided in
Sec. 585.416, we may suspend your payment obligation, as appropriate
for the term that is suspended, depending on the reasons for the
requested suspension.
(c) If BOEM orders a suspension, as provided in Sec. 585.417, your
payments, as appropriate for the term that is suspended, will be waived
during the suspension period.

Sec. 585.421 How long will a suspension be in effect?

A suspension will be in effect for the period specified by BOEM.
(a) BOEM will not approve a suspension request pursuant to Sec.
585.416 for a period longer than 2 years.
(b) If BOEM determines that the circumstances giving rise to a
suspension ordered under Sec. 585.417 cannot be resolved within 5
years, the Secretary may initiate cancellation of the lease or grant, as
provided in Sec. 585.437.

Sec. Sec. 585.422-585.424 [Reserved]

Lease or Grant Renewal

Sec. 585.425 May I obtain a renewal of my lease or grant
before it terminates?

You may request renewal of the operations term of your lease or the
original authorized term of your grant. BOEM, at its discretion, may
approve a renewal request to conduct substantially similar activities as
were originally authorized under the lease or grant. BOEM will not
approve a renewal request that involves development of a type of
renewable energy not originally authorized in the lease or grant. BOEM
may revise or adjust payment terms of the original lease, as a condition
of lease renewal.

Sec. 585.426 When must I submit my request for renewal?

(a) You must request a renewal from BOEM:
(1) No later than 180 days before the termination date of your
limited lease or grant.
(2) No later than 2 years before the termination date of the
operations term of your commercial lease.
(b) You must submit to BOEM all information we request pertaining to
your lease or grant and your renewal request.

Sec. 585.427 How long is a renewal?

BOEM will set the term of a renewal at the time of renewal on a
case-by-case basis.

[[Page 578]]

(a) For commercial leases, a renewal term will not exceed the
original operations term unless a longer term is negotiated by the
applicable parties.
(b) For limited leases, a renewal term will not exceed the original
operations term.
(c) For RUE and ROW grants, a renewal will continue for as long as
the associated activities are conducted and facilities properly
maintained and used for the purpose for which the grant was made, unless
otherwise expressly stated.

Sec. 585.428 What effect does applying for a renewal have
on my activities and payments?

If you timely request a renewal:
(a) You may continue to conduct activities approved under your lease
or grant under the original terms and conditions for as long as your
request is pending decision by BOEM.
(b) You may request a suspension of your lease or grant, as provided
in Sec. 585.416, while we consider your request.
(c) For the period BOEM considers your request for renewal, you must
continue to make all payments in accordance with the original terms and
conditions of your lease or grant.

Sec. 585.429 What criteria will BOEM consider in deciding whether
to renew a lease or grant?

BOEM will consider the following criteria in deciding whether to
renew a lease or grant:
(a) Design life of existing technology.
(b) Availability and feasibility of new technology.
(c) Environmental and safety record of the lessee or grantee.
(d) Operational and financial compliance record of the lessee or
grantee.
(e) Competitive interest and fair return considerations.
(f) Effects of the lease or grant on generation capacity and
reliability within the regional electrical distribution and transmission
system.

Sec. Sec. 585.430-585.431 [Reserved]

Lease or Grant Termination

Sec. 585.432 When does my lease or grant terminate?

Your lease or grant terminates on whichever of the following dates
occurs first:
(a) The expiration of the applicable term of your lease or grant,
unless your term is automatically extended under Sec. 585.235 or Sec.
585.236, a request for renewal of your lease or grant is pending a
decision by BOEM, or your lease or grant is suspended or renewed as
provided in this subpart;
(b) A cancellation, as set forth in Sec. 585.437; or
(c) Relinquishment, as set forth in Sec. 585.435.

Sec. 585.433 What must I do after my lease or grant terminates?

(a) After your lease or grant terminates, you must:
(1) Make all payments due, including any accrued rentals and
deferred bonuses; and
(2) Perform any other outstanding obligations under the lease or
grant within 6 months.
(b) Within 2 years following termination of a lease or grant, you
must remove or dispose of all facilities, installations, and other
devices permanently or temporarily attached to the seabed on the OCS in
accordance with a plan or application approved by BOEM under subpart I
of this part.
(c) If you fail to comply with your approved decommissioning plan or
application:
(1) BOEM may call for the forfeiture of your financial assurance;
and
(2) You remain liable for removal or disposal costs and responsible
for accidents or damages that might result from such failure.

Sec. 585.434 [Reserved]

Lease or Grant Relinquishment

Sec. 585.435 How can I relinquish a lease or a grant
or parts of a lease or grant?

(a) You may surrender the lease or grant, or an officially
designated subdivision thereof, by filing one paper

[[Page 579]]

copy and one electronic copy of a relinquishment application with BOEM.
A relinquishment takes effect on the date we approve your application,
subject to the continued obligation of the lessee and the surety to:
(1) Make all payments due on the lease or grant, including any
accrued rent and deferred bonuses;
(2) Decommission all facilities on the lease or grant to be
relinquished to the satisfaction of BOEM; and
(3) Perform any other outstanding obligations under the lease or
grant.
(b) Your relinquishment application must include:
(1) Name;
(2) Contact name;
(3) Telephone number;
(4) Fax number;
(5) E-mail address;
(6) BOEM-assigned lease or grant number, and, if applicable, the
name of any facility;
(7) A description of the geographic area you are relinquishing;
(8) The name, title, and signature of your authorizing official (the
name, title, and signature must match exactly the name, title, and
signature in BOEM qualification records); and
(9) A statement that you will adhere to the requirements of subpart
I of this part.
(c) If you have submitted an application to relinquish a lease or
grant, you will be billed for any outstanding payments that are due
before the relinquishment takes effect, as provided in paragraph (a) of
this section.

Lease or Grant Contraction

Sec. 585.436 Can BOEM require lease or grant contraction?

At an interval no more frequent than every 5 years, the BOEM may
review your lease or grant area to determine whether the lease or grant
area is larger than needed to develop the project and manage activities
in a manner that is consistent with the provisions of this part. BOEM
will notify you of our proposal to contract the lease or grant area.
(a) BOEM will give you the opportunity to present orally or in
writing information demonstrating that you need the area in question to
manage lease or grant activities consistent with these regulations.
(b) Prior to taking action to contract the lease or grant area, BOEM
will issue a decision addressing your contentions that the area is
needed.
(c) You may appeal this decision under Sec. 585.118 of this part.

Lease or Grant Cancellation

Sec. 585.437 When can my lease or grant be canceled?

(a) The Secretary will cancel any lease or grant issued under this
part upon proof that it was obtained by fraud or misrepresentation, and
after notice and opportunity to be heard has been afforded to the lessee
or grant holder.
(b) The Secretary may cancel any lease or grant issued under this
part when:
(1) The Secretary determines after notice and opportunity for a
hearing that, with respect to the lease or grant that would be canceled,
the lessee or grantee has failed to comply with any applicable provision
of the OCS Lands Act or these regulations; any order of the Director; or
any term, condition or stipulation contained in the lease or grant, and
that the failure to comply continued 30 days (or other period BOEM
specifies) after you receive notice from BOEM. The Secretary will mail a
notice by registered or certified letter to the lessee or grantee at its
record post office address;
(2) The Secretary determines after notice and opportunity for a
hearing that you have terminated commercial operations under your COP,
as provided in Sec. 585.635, or other approved activities under your
GAP, as provided in Sec. 585.656;
(3) Required by National security or defense; or
(4) The Secretary determines after notice and opportunity for a
hearing that continued activity under the lease or grant:
(i) Would cause serious harm or damage to natural resources; life
(including human and wildlife); property; the marine, coastal, or human
environment; or sites, structures, or objects of historical or
archaeological significance; and

[[Page 580]]

(ii) That the threat of harm or damage would not disappear or
decrease to an acceptable extent within a reasonable period of time; and
(iii) The advantages of cancellation outweigh the advantages of
continuing the lease or grant in force.

Subpart E_Payments and Financial Assurance Requirements

Payments

Sec. 585.500 How do I make payments under this part?

(a) For acquisition fees or the initial 12-months' rent paid for the
preliminary term of your lease, you must make your electronic payments
through the Fees for Services page on the BOEM Web site at http://
www.boem.gov, and you must include one copy of the Pay.gov confirmation
receipt page with your unsolicited request.
(b) For all other required rent payments and for operating fee
payments, you must make your payments as required in 30 CFR 1218.51.
(c) This table summarizes payments you must make for leases and
grants, unless otherwise specified in the Final Sale Notice:

--------------------------------------------------------------------------------------------------------------------------------------------------------
Payment Amount Due date Payment mechanism Section reference
--------------------------------------------------------------------------------------------------------------------------------------------------------
Initial payments for leases
--------------------------------------------------------------------------------------------------------------------------------------------------------
(1) If your lease is issued Bid Deposit........... As set in Final Sale With bid............. Pay.Gov.............. Sec. 585.501.
competitively, Notice/depends on bid.
Bonus Balance......... ...................... Lease issuance....... 30 CFR 1218.51.......
(2) If your lease is issued non- Acquisition Fee....... $0.25 per acre, unless With application..... Pay.gov.............. Sec. 585.502.
competitively. otherwise set by the
Director.
(3) All leases..................... Initial Rent.......... $3 per acre per year.. 45 days after lease Pay.gov.............. Sec. 585.503.
issuance.
--------------------------------------------------------------------------------------------------------------------------------------------------------
Subsequent payments for leases and project easements
--------------------------------------------------------------------------------------------------------------------------------------------------------
(4) All leases..................... Subsequent Rent....... $3 per acre per year.. Annually............. 30 CFR 1218.51....... Sec. Sec. 585.503
and 585.504.
(5) If you have a project easement. Rent.................. Greater of $5 per acre When operations term 30 CFR 1218.51....... Sec. 585.507.
per year or $450 per for associated lease
year. starts, then
annually.
(7) If your commercial lease is Operating Fee......... Determined by the Annually............. 30 CFR 1218.51....... Sec. 585.506.
producing, formula in Sec.
585.506.
--------------------------------------------------------------------------------------------------------------------------------------------------------
Payments for ROW grants and RUE grants*
--------------------------------------------------------------------------------------------------------------------------------------------------------
(8) All ROW grants and RUE grants.. Initial Rent.......... $70 per statute mile, Grant Issuance....... Pay.gov.............. Sec. 585.508.
and the greater of $5
per acre per year or
$450 per year.
Subsequent Rent....... ...................... Annually or in 5-year 30 CFR 1218.51.......
batches.
--------------------------------------------------------------------------------------------------------------------------------------------------------
* There is no acquisition fee for ROW grants or RUE grants.

[76 FR 64623, Oct. 18, 2011, as amended at 79 FR 21623, Apr. 17, 2014]

Sec. 585.501 What deposits must I submit for a competitively issued lease,
ROW grant, or RUE grant?

(a) For a competitive lease or grant that we offer through sealed
bidding, you must submit a deposit of 20 percent of the total bid
amount, unless some other amount is specified in the Final Sale Notice.
(b) For a competitive lease that we offer through ascending bidding,
you must submit a deposit as established in the Final Sale Notice.

[[Page 581]]

(c) You must pay any balances on accepted high bids in accordance
with the Final Sale Notice, this part, and your lease or grant
instrument.
(d) The deposit will be forfeited for any successful bidder who
fails to execute the lease within the prescribed time, or otherwise does
not comply with the regulations concerning acquisition of a lease or
grant or stipulations in the Final Sale Notice.

Sec. 585.502 What initial payment requirements must I meet to obtain
a noncompetitive lease, ROW grant, or RUE grant?

When requesting a noncompetitive lease, you must meet the initial
payment (acquisition fee) requirements of this section, unless specified
otherwise in your lease instrument. No initial payment is required when
requesting noncompetitive ROW grants and RUE grants.
(a) If you request a noncompetitive lease, you must submit an
acquisition fee of $0.25 per acre, unless otherwise set by the Director,
as provided in Sec. 585.500.
(b) If BOEM determines there is no competitive interest, we will
then:
(1) Retain your acquisition fee if we issue you a lease; or
(2) Refund your acquisition fee, without interest, if we do not
issue your requested lease.
(c) If we determine that there is a competitive interest in an area
you requested, then we will proceed with a competitive lease sale
process provided for in subpart B of this part, and we will:
(1) Apply your acquisition fee to the required deposit for your bid
amount if you submit a bid;
(2) Apply your acquisition fee to your bonus bid if you acquire the
lease; or
(3) Retain your acquisition fee if you do not bid for or acquire the
lease.

Sec. 585.503 What are the rent and operating fee requirements
for a commercial lease?

(a) The rent for a commercial lease is $3 per acre per year, unless
otherwise established in the Final Sale Notice or lease.
(1) You must pay ONRR the initial 12-months' rent 45 days after you
receive the lease copies from BOEM in accordance with the requirements
provided in Sec. 585.500(a).
(2) You must pay ONRR, under the regulations at 30 CFR part 1218,
rent at the beginning of each subsequent 1-year period in accordance
with the regulations at 30 CFR 1218.51 for the entire lease area until
the facility begins to generate commercially, as specified in Sec.
585.506 or as otherwise specified in the Final Sale Notice or lease
instrument:
(i) For leases issued competitively, the BOEM will specify in the
Final Sale Notice and lease any adjustment to the rent fee to take
effect during the operations term and prior to the commercial
generation.
(ii) For leases issued noncompetitively, the BOEM will specify in
the lease any adjustment to the rent fee to take effect during the
operations term and prior to the commercial generation.
(3) You must pay ONRR, under the regulations at 30 CFR part 1218,
the rent for a project easement in addition to the lease rent, as
provided in Sec. 585.507. You must commence rent payments for your
project easement upon our approval of your COP or GAP.
(b) After your lease begins commercial generation of electricity or
on the date specified by BOEM, you must pay operating fees in the amount
specified in Sec. 585.506:
(1) For leases issued competitively, BOEM will specify in the Final
Sale Notice and lease the date when operating fees commence; and
(2) For leases issued noncompetitively, BOEM will specify in the
lease the date when operating fee commences.

[76 FR 64623, Oct. 18, 2011, as amended at 79 FR 21623, Apr. 17, 2014]

Sec. 585.504 How are my payments affected if I develop my lease in phases?

If you develop your commercial lease in phases, as approved by us in
your COP under Sec. 585.629, you must pay ONRR, under the regulations
at 30 CFR part 1218:
(a) Rent on the portion of the lease that is not authorized for
commercial operations.

[[Page 582]]

(b) Operating fees on the portion of the lease that is authorized
for commercial operations, in the amount specified in Sec. 585.506 and
as described in Sec. 585.503(b).
(c) Rent for a project easement in addition to lease rent, as
provided in Sec. 585.507. You must commence rent payments for your
project easement upon our approval of your COP.

Sec. 585.505 What are the rent and operating fee requirements
for a limited lease?

(a) The rent for a limited lease is $3 per acre per year, unless
otherwise established in the Final Sale Notice and your lease
instrument.
(b) You must pay ONRR the initial 12-months' rent 45 days after you
receive the lease copies from BOEM in accordance with the requirements
provided in Sec. 585.500(a).
(c) You must pay ONRR, under the regulations at 30 CFR part 1218,
rent at the beginning of each subsequent 1-year period on the entire
lease area for the duration of your operations term in accordance with
the regulations at 30 CFR 1218.51.
(d) BOEM will not charge an operating fee for the authorized sale of
power from a limited lease.

[76 FR 64623, Oct. 18, 2011, as amended at 79 FR 21623, Apr. 17, 2014]

Sec. 585.506 What operating fees must I pay on a commercial lease?

If you are generating electricity, you must pay ONRR, under the
regulations at 30 CFR part 1218, operating fees on your commercial lease
when you begin commercial generation, as described in Sec. 585.503.
(a) BOEM will determine the annual operating fee for activities
relating to the generation of electricity on your lease based on the
following formula,

F = M * H * c * P * r,

Where:

(1) F is the dollar amount of the annual operating fee;
(2) M is the nameplate capacity expressed in megawatts;
(3) H is the number of hours in a year, equal to 8,760, used to
calculate an annual payment;
(4) c is the ``capacity factor'' representing the anticipated efficiency
of the facility's operation expressed as a decimal between
zero and one;
(5) P is a measure of the annual average wholesale electric power price
expressed in dollars per megawatt hour, as provided in
paragraph (c)(2) of this section; and
(6) r is the operating fee rate expressed as a decimal between zero and
one.

(b) The annual operating fee formula relating to the value of annual
electricity generation is restated as:

--------------------------------------------------------------------------------------------------------------------------------------------------------
M (nameplate H (hours per c (capacity r (operating fee
F (annual operating fee) = capacity) * year) * factor) * P (power price) * rate)
--------------------------------------------------------------------------------------------------------------------------------------------------------

--------------------------------------------------------------------------------------------------------------------------------------------------------

(c) BOEM will specify operating fee parameters in the Final Sale
Notice for commercial leases issued competitively and in the lease for
those issued noncompetitively.
(1) Unless BOEM specifies otherwise, in the operating fee rate,
``r'' is 0.02 for each year the operating fee applies when you begin
commercial generation of electricity. We may apply a different fee rate
for new projects (i.e., a new generation based on new technology) after
considering factors such as program objectives, state of the industry,
project type, and project potential. Also, we may agree to reduce or
waive the fee rate under Sec. 585.510.
(2) The power price ``P,'' for each year when the operating fee
applies, will be determined annually. The process by which the power
price will be determined will be specified in the Final Sale Notice and/
or in the lease. BOEM:
(i) Will use the most recent annual average wholesale power price in
the State in which a project's transmission cables make landfall, as
published by the DOE, Energy Information Administration (EIA), or other
publicly available wholesale power price indices; and
(ii) May adjust the published average wholesale power price to
reflect documented variations by State or within a region and recent
market conditions.

[[Page 583]]

(3) BOEM will select the capacity factor ``c'' based upon applicable
analogs drawn from present and future domestic and foreign projects that
operate in comparable conditions and on comparable scales.
(i) Upon the completion of the first year of commercial operations
on the lease, BOEM may adjust the capacity factor as necessary (to
accurately represent a comparison of actual production over a given
period of time with the amount of power a facility would have produced
if it had run at full capacity) in a subsequent year.
(ii) After the first adjustment, BOEM may adjust the capacity factor
(to accurately represent a comparison of actual generation over a given
period of time with the amount of power a facility would have generated
if it had run at full capacity) no earlier than in 5-year intervals from
the most recent year that BOEM adjusts the capacity factor.
(iii) The process by which BOEM will adjust the capacity factor,
including any calculations (incorporating an average capacity factor
reflecting actual operating experience), will be specified in the lease.
The operator or lessee may request review and adjustment of the capacity
factor under Sec. 585.510.
(4) Ten days after the anniversary date of when you began to
commercially generate electricity, you must submit to BOEM documentation
of the gross annual generation of electricity produced by the generating
facility on the lease. You must use the same information collection form
as authorized by the EIA for this information.
(5) For the nameplate capacity ``M,'' BOEM will use the total
installed capacity of the equipment you install, as specified in your
approved COP.
(d) You must submit all operating fee payments to BOEM in accordance
with the provisions under 30 CFR 1218.51.
(e) BOEM will establish the operating fee in the Final Sale Notice
or in the lease on a case-by-case basis for:
(1) Activities that do not relate to the generation of electricity
(e.g., hydrogen production), and
(2) Leases issued for hydrokinetic activities requiring a FERC
license.

Sec. 585.507 What rent payments must I pay on a project easement?

(a) You must pay ONRR, under the regulations at 30 CFR part 1218, a
rent fee for your project easement of $5 per acre, subject to a minimum
of $450 per year, unless specified otherwise in the Final Sale Notice or
lease:
(1) The size of the project easement area for a cable or a pipeline
is the full length of the corridor and a width of 200 feet (61 meters),
centered on the cable or pipeline; and
(2) The size of a project easement area for an accessory platform is
limited to the aerial extent of anchor chains and other facilities and
devices associated with the accessory.
(b) You must commence rent payments for your project easement upon
our approval of your COP or GAP:
(1) You must make the first rent payment when the operations term
begins, as provided in Sec. 585.500;
(2) You must submit all subsequent rent payments in accordance with
the regulations at 30 CFR 1218.51; and
(3) You must continue to pay annual rent for your project easement
until your lease is terminated.

Sec. 585.508 What rent payments must I pay on ROW grants or RUE grants
associated with renewable energy projects?

(a) For each ROW grant BOEM approves under subpart C of this part,
you must pay ONRR, under the regulations at 30 CFR part 1218, an annual
rent as follows, unless specified otherwise in the Final Sale Notice:
(1) A fee of $70 for each nautical mile or part of a nautical mile
of the OCS that your ROW crosses; and
(2) An additional $5 per acre, subject to a minimum of $450 for use
of the entire affected area, if you hold a ROW grant that includes a
site outside the corridor of a 200-foot width (61 meters), centered on
the cable or pipeline. The affected area includes the areal extent of
anchor chains, risers, and other devices associated with a site outside
the corridor.
(b) For each RUE grant BOEM approves under subpart C of this part,
you must pay ONRR, under the regulations at 30 CFR part 1218, a rent of:
(1) $5 per acre per year; or

[[Page 584]]

(2) A minimum of $450 per year.
(c) You must make the rent payments required by paragraphs (a) and
(b) of this section on:
(1) An annual basis;
(2) For a 5-year period; or
(3) For multiples of 5 years.
(d) You must make the first annual rent payment upon approval of
your ROW grant or RUE grant request, as provided in Sec. 585.500, and
all subsequent rent payments to ONRR in accordance with the regulations
at 30 CFR 1218.51.

Sec. 585.509 Who is responsible for submitting lease
or grant payments to BOEM?

(a) For each lease, ROW grant, or RUE grant issued under this part,
you must identify one person who is responsible for all payments due and
payable under the provisions of the lease or grant. The responsible
person identified is designated as the payor, and you must document
acceptance of such responsibilities, as provided in 30 CFR 1218.52.
(b) All payors must submit payments and maintain auditable records
in accordance with guidance we issue or any applicable regulations in
subchapter A of this chapter. In addition, the lessee or grant holder
must also maintain such auditable records.

Sec. 585.510 May BOEM reduce or waive my lease or grant payments?

(a) BOEM Director may reduce or waive the rent or operating fee or
components of the operating fee, such as the fee rate or capacity
factor, when the Director determines that it is necessary to encourage
continued or additional activities.
(b) When requesting a reduction or waiver, you must submit an
application to us that includes all of the following:
(1) The number of the lease, ROW grant, or RUE grant involved;
(2) Name of each lessee or grant holder of record;
(3) Name of each operator;
(4) A demonstration that:
(i) Continued activities would be uneconomic without the requested
reduction or waiver, or
(ii) A reduction or waiver is necessary to encourage additional
activities; and
(5) Any other information required by the Director.
(c) No more than 6 years of your operations term will be subject to
a full waiver of the operating fee.

Sec. Sec. 585.511-585.514 [Reserved]

Financial Assurance Requirements for Commercial Leases

Sec. 585.515 What financial assurance must I provide
when I obtain my commercial lease?

(a) Before BOEM will issue your commercial lease or approve an
assignment of an existing commercial lease, you (or, for an assignment,
the proposed assignee) must guarantee compliance with all terms and
conditions of the lease by providing either:
(1) A $100,000 minimum, lease-specific bond; or
(2) Another approved financial assurance instrument guaranteeing
performance up to $100,000, as specified in Sec. Sec. 585.526 through
585.529.
(b) You meet the financial assurance requirements under this subpart
if your designated lease operator provides a $100,000 minimum, lease-
specific bond or other approved financial assurance that guarantees
compliance with all terms and conditions of the lease.
(1) The dollar amount of the minimum, lease-specific financial
assurance in paragraphs (a)(1) and (b) of this section will be adjusted
to reflect changes in the Consumer Price Index-All Urban Consumers (CPI-
U) or a substantially equivalent index if the CPI-U is discontinued; and
(2) The first CPI-U-based adjustment can be made no earlier than the
5-year anniversary of the adoption of this rule. Subsequent CPI-U-based
adjustments may be made every 5 years thereafter.

[[Page 585]]

Sec. 585.516 What are the financial assurance requirements for each stage
of my commercial lease?

(a) The basic financial assurance requirements for each stage of
your commercial lease are as follows:

------------------------------------------------------------------------
Before BOEM will . . . You must provide . . .
------------------------------------------------------------------------
(1) Issue a commercial lease or approve A $100,000 minimum, lease-
an assignment of an existing specific financial assurance.
commercial lease.
(2) Approve your SAP................... A supplemental bond or other
financial assurance, in an
amount determined by BOEM, if
upon reviewing your SAP, BOEM
determines that a supplemental
bond is required in addition
to your minimum lease-specific
bond, due to the complexity,
number, and location of any
facilities involved in your
site assessment activities.
(3) Approve your COP................... A supplemental bond or other
financial assurance, in an
amount determined by BOEM
based on the complexity,
number, and location of all
facilities involved in your
planned activities and
commercial operation. The
supplemental financial
assurance requirement is in
addition to your lease-
specific bond and, if
applicable, the previous
supplement associated with SAP
approval.
(4) Allow you to install facilities A decommissioning bond or other
approved in your COP. financial assurance, in an
amount determined by BOEM
based on anticipated
decommissioning costs. BOEM
will allow you to provide your
financial assurance for
decommissioning in accordance
with the number of facilities
installed or being installed.
BOEM must approve the schedule
for providing the appropriate
financial assurance coverage.
------------------------------------------------------------------------

(b) Each bond or other financial assurance must guarantee compliance
with all terms and conditions of the lease. You may provide a new bond
or increase the amount of your existing bond, to satisfy any additional
financial assurance requirements.
(c) For hydrokinetic commercial leases, supplemental financial
assurance may be required in an amount determined by BOEM before FERC
issues a license.

Sec. 585.517 How will BOEM determine the amounts of the supplemental
and decommissioning financial assurance requirements associated
with commercial leases?

(a) BOEM will base the determination for the amounts of the SAP,
COP, and decommissioning financial assurance requirements on estimates
of the cost to meet all accrued lease obligations.
(b) We determine the amount of the supplemental and decommissioning
financial assurance requirements on a case-by-case basis. The amount of
the financial assurance must be no less than the amount required to meet
all lease obligations, including:
(1) The projected amount of rent and other payments due the
Government over the next 12 months;
(2) Any past due rent and other payments;
(3) Other monetary obligations; and
(4) The estimated cost of facility decommissioning, as required by
subpart I of this part.
(c) If your cumulative potential obligations and liabilities
increase or decrease, we may adjust the amount of supplemental or the
decommissioning financial assurance.
(1) If we propose adjusting your financial assurance amount, we will
notify you of the proposed adjustment and give you an opportunity to
comment; and
(2) We may approve a reduced financial assurance amount if you
request it and if the reduced amount that you request continues to be
greater than the sum of:
(i) The projected amount of rent and other payments due the
Government over the next 12 months;
(ii) Any past due rent and other payments;
(iii) Other monetary obligations; and

[[Page 586]]

(iv) The estimated cost of facility decommissioning.

Sec. Sec. 585.518-585.519 [Reserved]

Financial Assurance for Limited Leases, ROW Grants, and RUE Grants

Sec. 585.520 What financial assurance must I provide when I obtain
my limited lease, ROW grant, or RUE grant?

(a) Before BOEM will issue your limited lease, ROW grant, or RUE
grant, you or a proposed assignee must guarantee compliance with all
terms and conditions of the lease or grant by providing either:
(1) A $300,000 minimum, lease- or grant-specific bond; or
(2) Another approved financial assurance instrument of such minimum
level as specified in Sec. Sec. 585.526 through 585.529.
(b) You meet the financial assurance requirements under this subpart
if your designated lease or grant operator provides a minimum limited
lease-specific or grant-specific bond in an amount sufficient to
guarantee compliance with all terms and conditions of the limited lease
or grant.
(1) The dollar amount of the minimum, lease- or grant-specific
financial assurance in paragraph (a)(1) of this section will be adjusted
to reflect changes in the CPI-U or a substantially equivalent index if
the CPI-U is discontinued; and
(2) The first CPI-U-based adjustment can be made no earlier than the
5-year anniversary of the adoption of this rule. Subsequent CPI-U-based
adjustments may be made every 5 years thereafter.

Sec. 585.521 Do my financial assurance requirements change
as activities progress on my limited lease or grant?

(a) BOEM may require you to increase the level of your financial
assurance as activities progress on your limited lease or grant. We will
base the determination for the amount of financial assurance
requirements on our estimate of the cost to meet all accrued lease or
grant obligations, including:
(1) The projected amount of rent and other payments due the
Government over the next 12 months;
(2) Any past due rent and other payments;
(3) Other monetary obligations; and
(4) The estimated cost of facility decommissioning.
(b) You may satisfy the requirement for increased financial
assurance levels for the limited lease or grant by increasing the amount
of your existing bond or replacing your existing bond.
(c) BOEM will authorize you to establish a separate decommissioning
bond or other financial assurance for your limited lease or grant.
(1) The separate decommissioning bond or other financial assurance
instrument must meet the requirements specified in Sec. Sec. 585.525
through 585.529.
(2) BOEM will allow you to provide your financial assurance for
decommissioning in accordance with the number of facilities installed or
being installed. BOEM must approve the schedule for providing the
appropriate financial assurance coverage.

Sec. Sec. 585.522-585.524 [Reserved]

Requirements for Financial Assurance Instruments

Sec. 585.525 What general requirements must a financial assurance
instrument meet?

(a) Any bond or other acceptable financial assurance instrument that
you provide must:
(1) Be payable to BOEM upon demand; and
(2) Guarantee compliance of all lessees, grant holders, operators,
and payors with all terms and conditions of the lease or grant, any
subsequent approvals and authorizations, and all applicable regulations.
(b) All bonds and other forms of financial assurance must be on or
in a form approved by BOEM. You may submit this on an approved form that
you have reproduced or generated by use of a computer. If the document
you submit omits any terms and conditions that are included on the BOEM-
approved form, your bond is deemed to contain the omitted terms and
conditions.

[[Page 587]]

(c) Surety bonds must be issued by an approved surety listed in the
current Treasury Circular 570, as required by 31 CFR 223.16. You may
obtain a copy of Circular 570 from the Treasury Web site at http://
www.fms.treas.gov/c570/.
(d) Your surety bond cannot exceed the underwriting limit listed in
the current Treasury Circular 570, except as permitted therein.
(e) You and a qualified surety must execute your bond. When the
surety is a corporation, an authorized corporate officer must sign the
bond and attest to it over the corporate seal.
(f) You may not terminate the period of liability of your bond or
cancel your bond, except as provided in this subpart. Bonds must
continue in full force and effect even though an event has occurred that
could diminish or terminate a surety's obligation under State law.
(g) Your surety must notify you and BOEM within 5 business days
after:
(1) It initiates any judicial or administrative proceeding alleging
its insolvency or bankruptcy; or
(2) The Treasury decertifies the surety.

Sec. 585.526 What instruments other than a surety bond may I use
to meet the financial assurance requirement?

(a) You may use other types of security instruments, if BOEM
determines that such security protects BOEM to the same extent as the
surety bond. BOEM will consider pledges of the following:
(1) U.S. Department of Treasury securities identified in 31 CFR part
225;
(2) Cash in an amount equal to the required dollar amount of the
financial assurance, to be deposited and maintained in a Federal
depository account of the U.S. Treasury by BOEM;
(3) Certificates of deposit or savings accounts in a bank or
financial institution organized or authorized to transact business in
the United States with:
(i) Minimum net assets of $500,000,000; and
(ii) Minimum Bankrate.com Safe & Sound rating of 3 Stars, and
Capitalization, Assets, Equity and Liquidity (CAEL) rating of 3 or less;
(4) Negotiable U.S. Government, State, and municipal securities or
bonds having a market value of not less than the required dollar amount
of the financial assurance and maintained in a Securities Investors
Protection Corporation insured trust account by a licensed securities
brokerage firm for the benefit of the BOEM;
(5) Investment-grade rated securities having a Standard and Poor's
rating of AAA or an equivalent rating from a nationally recognized
securities rating service having a market value of not less than the
required dollar amount of the financial assurance and maintained in a
Securities Investors Protection Corporation insured trust account by a
licensed securities brokerage firm for the benefit of BOEM; and
(6) Insurance, if its form and function is such that the funding or
enforceable pledges of funding are used to guarantee performance of
regulatory obligations in the event of default on such obligations by
the lessee. Insurance must have an A.M. Best rating of ``superior'' or
an equivalent rating from a nationally recognized insurance rating
service.
(b) If you use a Treasury security:
(1) You must post 115 percent of your financial assurance amount;
(2) You must monitor the collateral value of your security. If the
collateral value of your security as determined in accordance with the
31 CFR part 203 Collateral Margins Table (which can be found at http://
www.treasurydirect.gov) falls below the required level of coverage, you
must pledge additional security to provide 115 percent of the required
amount; and
(3) You must include with your pledge authority for us to sell the
security and use the proceeds if we determine that you have failed to
comply with any of the terms and conditions of your lease or grant, any
subsequent approval or authorization, or applicable regulations.
(c) If you use the instruments described in paragraphs (a)(4) or
(a)(5) of this section, you must provide BOEM by the end of each
calendar year a certified statement describing the nature and market
value of the instruments maintained in that account, and including any
current statements or reports furnished by the brokerage firm

[[Page 588]]

to the lessee concerning the asset value of the account.

Sec. 585.527 May I demonstrate financial strength and reliability
to meet the financial assurance requirement for lease or grant activities?

BOEM may allow you to use your financial strength and reliability to
meet financial assurance requirements. We will make this determination
based on audited financial statements, business stability, reliability,
and compliance with regulations.
(a) You must provide the following information if you want to
demonstrate financial strength and reliability to meet your financial
assurance requirements:
(1) Audited financial statements (including auditor's certificate,
balance sheet, and profit and loss sheet) that show you have financial
capacity substantially in excess of existing and anticipated lease and
other obligations;
(2) Evidence that shows business stability based on 5 years of
continuous operation and generation of renewable energy on the OCS or
onshore;
(3) Evidence that shows reliability in meeting obligations based on
credit ratings or trade references, including names and addresses of
other lessees, contractors, and suppliers with whom you have dealt; and
(4) Evidence that shows a record of compliance with laws,
regulations, and lease, ROW, or RUE terms.
(b) If we approve your request to use your financial strength and
reliability to meet your financial assurance requirements, you must
submit annual updates to the information required by paragraph (a) of
this section. You must submit this information no later than March 31 of
each year.
(c) If the annual updates to the information required by paragraph
(a) of this section do not continue to demonstrate financial strength
and reliability or BOEM has reason to believe that you are unable to
meet the financial assurance requirements of this section, after notice
and opportunity for a hearing, BOEM will terminate your ability to use
financial strength and reliability for financial assurance and require
you to provide another type of financial assurance. You must provide
this new financial assurance instrument within 90 days after we
terminate your use of financial strength and reliability.

Sec. 585.528 May I use a third-party guaranty to meet the financial
assurance requirement for lease or grant activities?

(a) You may use a third-party guaranty if the guarantor meets the
criteria prescribed in paragraph (b) of this section and submits an
agreement meeting the criteria prescribed in paragraph (c) of this
section. The agreement must guarantee compliance with the obligations of
all lessees and operators and grant holders.
(b) BOEM will consider the following factors in deciding whether to
accept an agreement:
(1) The length of time that your guarantor has been in continuous
operation as a business entity. You may exclude periods of interruption
that are beyond the guarantor's control by demonstrating, to the
satisfaction of the Director, that the interruptions do not affect the
likelihood of your guarantor remaining in business during the SAP, COP,
and decommissioning stages of activities covered by the indemnity
agreement.
(2) Financial information available in the public record or
submitted by your guarantor in sufficient detail to show us that your
guarantor meets the criterion stated in paragraph (b)(4) of this
section. Such detail includes:
(i) The current rating for your guarantor's most recent bond
issuance by a generally recognized bond rating service such as Moody's
Investor Service or Standard and Poor's Corporation;
(ii) Your guarantor's net worth, taking into account liabilities for
compliance with all terms and conditions of your lease, regulations, and
other guarantees;
(iii) Your guarantor's ratio of current assets to current
liabilities, taking into account liabilities for compliance with all
terms and conditions of your lease, regulations, and other guarantees;
and
(iv) Your guarantor's unencumbered domestic fixed assets.
(3) If the information in paragraph (b)(2) of this section is not
publicly

[[Page 589]]

available, your guarantor must submit the information in the following
table, to be updated annually within 90 days of the end of the fiscal
year (FY) or as otherwise prescribed.

------------------------------------------------------------------------
Your guarantor must submit . . . That . . .
------------------------------------------------------------------------
(i) Financial statements for the most Include a report by an
recently completed FY. independent certified public
accountant containing the
accountant's audit or review
opinion of the statements. The
report must be prepared in
conformance with generally
accepted accounting principles
and contain no adverse
opinion.
(ii) Financial statement for completed Your guarantor's financial
quarter in the current FY. officer certifies to be
correct.
(iii) Additional information related to Your guarantor's financial
bonds, if requested by the Director. officer certifies to be
correct.
------------------------------------------------------------------------

(4) Your guarantor's total outstanding and proposed guarantees must
not exceed 25 percent of its unencumbered domestic net worth.
(c) Your guarantor must submit an agreement executed by the
guarantor and all parties bound by the agreement. All parties are bound
jointly and severally and must meet the qualifications set forth in
Sec. 585.107.
(1) When any party is a corporation, two corporate officers
authorized to execute the guaranty agreement on behalf of the
corporation must sign the agreement.
(2) When any party is a partnership, joint venture, or syndicate,
the guaranty agreement must bind each party who has a beneficial
interest in your guarantor and provide that, upon BOEM demand under your
guaranty, each party is jointly and severally liable for compliance with
all terms and conditions of your lease(s) or grant(s) covered by the
agreement.
(3) When forfeiture of the guaranty is called for, the agreement
must provide that your guarantor will either bring your lease(s) or
grant(s) into compliance or provide, within 7 days, sufficient funds to
permit BOEM to complete corrective action.
(4) The guaranty agreement must contain a confession of judgment,
providing that, if we determine that you are, or your operator or
operating rights owner is, in default, the guarantor must not challenge
the determination and must remedy the default.
(5) If you fail, or your operator or operating rights owner fails,
to comply with any law, term, or regulation, your guarantor must either
take corrective action or provide, within 7 days or other agreed upon
time period, sufficient funds for BOEM to complete corrective action.
Such compliance must not reduce your guarantor's liability.
(6) If your guarantor wants to terminate the period of liability,
your guarantor must notify you and us at least 90 days before the
proposed termination date, obtain our approval for termination of all or
a specified portion of the guarantee for liabilities arising after that
date, and remain liable for all your work performed during the period
the agreement is in effect.
(7) Each guaranty submitted pursuant to this section is deemed to
contain all the above terms, even if they are not actually in the
agreement.
(d) Before the termination of your guaranty, you must provide an
acceptable replacement in the form of a bond or other security.

Sec. 585.529 Can I use a lease- or grant-specific decommissioning account
to meet the financial assurance requirements related to decommissioning?

(a) In lieu of a surety bond, BOEM may authorize you to establish a
lease-, ROW grant-, or RUE grant-specific decommissioning account in a
federally-insured institution. The funds may not be withdrawn from the
account without our written approval.
(1) The funds must be payable to BOEM and pledged to meet your lease
or grant decommissioning and site clearance obligations; and
(2) You must fully fund the account within the time BOEM prescribes
to cover all costs of decommissioning including site clearance. BOEM
will estimate the cost of decommissioning, including site clearance.
(b) Any interest paid on the account will be treated as account
funds unless

[[Page 590]]

we authorize in writing that any interest be paid to the depositor.
(c) We may allow you to pledge Treasury securities, payable to BOEM
on demand, to satisfy your obligation to make payments into the account.
Acceptable Treasury securities and their collateral value are determined
in accordance with 31 CFR part 203, Collateral Margins Table (which can
be found at http://www.treasurydirect.gov).
(d) We may require you to commit a specified stream of revenues as
payment into the account so that the account will be fully funded, as
prescribed in paragraph (a)(2) of this section. The commitment may
include revenue from other operations.

Changes in Financial Assurance

Sec. 585.530 What must I do if my financial assurance lapses?

(a) If your surety is decertified by the Treasury, becomes bankrupt
or insolvent, or if your surety's charter or license is suspended or
revoked, or if any other approved financial assurance expires for any
reason, you must:
(1) Inform BOEM within 3 business days about the financial assurance
lapse; and
(2) Provide new financial assurance in the amount set by BOEM, as
provided in this subpart.
(b) You must notify BOEM within 3 business days after you learn of
any action filed alleging that you, your surety, or third-party
guarantor, is insolvent or bankrupt.

Sec. 585.531 What happens if the value of my financial assurance is reduced?

If the value of your financial assurance is reduced below the
required financial assurance amount because of a default or any other
reason, you must provide additional financial assurance sufficient to
meet the requirements of this subpart within 45 days or within a
different period as specified by BOEM.

Sec. 585.532 What happens if my surety wants to terminate
the period of liability of my bond?

(a) Terminating the period of liability of a bond ends the period
during which surety liability continues to accrue. The surety continues
to be responsible for obligations and liabilities that accrued during
the period of liability and before the date on which BOEM terminates the
period of liability under paragraph (b) of this section. The liabilities
that accrue during a period of liability include:
(1) Obligations that started to accrue before the beginning of the
period of liability and have not been met; and
(2) Obligations that began accruing during the period of liability.
(b) Your surety must submit to BOEM its request to terminate the
period of liability under its bond and notify you of that request. If
you intend to continue activities, or have not met all obligations of
your lease or grant, you must provide a replacement bond or alternative
form of financial assurance of equivalent or greater value. BOEM will
terminate that period of liability within 90 days after BOEM receives
the request.

Sec. 585.533 How does my surety obtain cancellation of my bond?

(a) BOEM will release a bond or allow a surety to cancel a bond, and
will relieve the surety from accrued obligations only if:
(1) BOEM determines that there are no outstanding obligations
covered by the bond; or
(2) The following occurs:
(i) BOEM accepts a replacement bond or an alternative form of
financial assurance in an amount equal to or greater than the bond to be
cancelled to cover the terminated period of liability;
(ii) The surety issuing the new bond has expressly agreed to assume
all outstanding liabilities under the original bond that accrued during
the period of liability that was terminated; and
(iii) The surety issuing the new bond has agreed to assume that
portion of the outstanding liabilities that accrued during the
terminated period of liability that exceeds the coverage of the bond
prescribed under Sec. Sec. 585.515, 585.516, 585.520, or 585.521, and
of which you were notified.
(b) When your lease or grant ends, your surety(ies) remain(s)
responsible, and BOEM will retain any financial assurance as follows:
(1) The period of liability ends when you cease all operations and
activities

[[Page 591]]

under the lease or grant, including decommissioning and site clearance;
(2) Your surety or collateral financial assurance will not be
released until 7 years after the lease ends, or a longer period as
necessary to complete any appeals or judicial litigation related to your
bonded obligation, or for BOEM to determine that all of your obligations
under the lease or grant have been satisfied; and
(3) BOEM will reduce the amount of your bond or return a portion of
your financial assurance if we determine that we need less than the full
amount of the bond or financial assurance to meet any possible future
obligations.

Sec. 585.534 When may BOEM cancel my bond?

When your lease or grant ends, your surety(ies) remain(s)
responsible, and BOEM will retain any pledged security as shown in the
following table:

------------------------------------------------------------------------
Your bond will not
Bond The period of be released until .
liability ends . . . . .
------------------------------------------------------------------------
(a) Bonds for commercial When BOEM determines Seven years after
leases submitted under Sec. that you have met the lease ends, or
585.515. all of your a longer period as
obligations under necessary to
the lease. complete any
appeals or judicial
litigation related
to your bond
obligation. BOEM
will reduce the
amount of your bond
or return a portion
of your security if
BOEM determines
that you need less
than the full
amount of the bond
to meet any
possible future
obligations.
(b) Supplemental or When BOEM determines (1) Seven years
decommissioning bonds that you have met after the lease
submitted under Sec. all your ends, or a longer
585.516. decommissioning, period as necessary
site clearance, and to complete any
other obligations. appeals or judicial
litigation related
to your bond
obligation. BOEM
will reduce the
amount of your bond
or return a portion
of your security if
BOEM determines
that you need less
than the full
amount of the bond
to meet any
possible future
obligations; and
(2) BOEM determines
that the potential
liability resulting
from any undetected
noncompliance is
not greater than
the amount of the
lease base bond.
(c) Bonds submitted under When BOEM determines Seven years after
Sec. Sec. 585.520 and that you have met the limited lease,
585.521 for limited leases, all of your ROW, or RUE grant
ROW grants, or RUE grants. obligations under or a longer period
the limited lease as necessary to
or grant. complete any
appeals or judicial
litigation related
to your bond
obligation. BOEM
will reduce the
amount of your bond
or return a portion
of your security if
BOEM determines
that you need less
than the full
amount of the bond
to meet any
possible future
obligations.
------------------------------------------------------------------------

Sec. 585.535 Why might BOEM call for forfeiture of my bond?

(a) BOEM may call for forfeiture of all or part of the bond, pledged
security, or other form of guaranty if:
(1) After notice and demand for performance by BOEM, you refuse or
fail, within the timeframe we prescribe, to comply with any term or
condition of your lease or grant, other authorization or approval, or
applicable regulations; or
(2) You default on one of the conditions under which we accepted
your bond.
(b) We may pursue forfeiture without first making demands for
performance against any co-lessee or holder of an interest in your ROW
or RUE, or other person approved to perform obligations under your lease
or grant.

Sec. 585.536 How will I be notified of a call for forfeiture?

(a) BOEM will notify you and your surety, including any provider of
financial assurance, in writing of the call for forfeiture and provide
the reasons for the forfeiture and the amount to be forfeited. We will
base the amount

[[Page 592]]

upon an estimate of the total cost of corrective action to bring your
lease or grant into compliance.
(b) We will advise you and your surety that you may avoid forfeiture
if, within 10 business days:
(1) You agree to and demonstrate in writing to BOEM that you will
bring your lease or grant into compliance within the timeframe we
prescribe, and you do so; or
(2) Your surety agrees to and demonstrates that it will bring your
lease or grant into compliance within the timeframe we prescribe, even
if the cost of compliance exceeds the face amount of the bond.

Sec. 585.537 How will BOEM proceed once my bond
or other security is forfeited?

(a) If BOEM determines that your bond or other security is
forfeited, we will collect the forfeited amount and use the funds to
bring your lease or grant(s) into compliance and correct any default.
(b) If the amount collected under your bond or other security is
insufficient to pay the full cost of corrective action, BOEM may take or
direct action to obtain full compliance and recover all costs in excess
of the forfeited bond from you or any co-lessee or co-grantee.
(c) If the amount collected under your bond or other security
exceeds the full cost of corrective action to bring your lease or
grant(s) into compliance, we will return the excess funds to the party
from whom the excess was collected.

Sec. Sec. 585.538-585.539 [Reserved]

Revenue Sharing With States

Sec. 585.540 How will BOEM equitably distribute revenues to States?

(a) BOEM will distribute among the eligible coastal States 27
percent of the following revenues derived from qualified projects, where
a qualified project and qualified project area is determined in Sec.
585.541 and an eligible State is determined in Sec. 585.542, with each
term defined in Sec. 585.112. Revenues subject to distribution to
eligible States include all bonuses, acquisition fees, rentals, and
operating fees derived from the entire qualified project area and
associated project easements not limited to revenues attributable to the
portion of the project area within 3 miles of the seaward boundary of a
coastal State. The revenues to be shared do not include administrative
fees such as service fees and those assessed for civil penalties and
forfeiture of bond or other surety obligations.
(b) The project area is the area included within a single lease or
grant. For each qualified project, BOEM will determine and announce the
project area and its geographic center at the time it grants or issues a
lease, easement, or right-of-way on the OCS. If a qualified project
lease or grant's boundaries change significantly due to actions pursuant
to Sec. Sec. 585.435 or 585.436, BOEM will re-evaluate the project area
to determine whether the geographic center has changed. If it has, BOEM
will re-determine State eligibility and shares accordingly.
(c) To determine each eligible State's share of the 27 percent of
the revenues for a qualified project, BOEM will use the inverse distance
formula, which apportions shares according to the relative proximity of
the nearest point on the coastline of each eligible State to the
geographic center of the qualified project area. If Si is
equal to the nearest distance from the geographic center of the project
area to the i = 1, 2, * * * nth eligible State's coastline, then
eligible State i would be entitled to the fraction Fi of the
27-percent aggregate revenue share due to all the eligible States
according to the formula:

Fi= (1/Si) / ([Sigma]i=1* *
*n(1/Si)).

Sec. 585.541 What is a qualified project for revenue sharing purposes?

A qualified project for the purpose of revenue sharing with eligible
coastal States is one authorized under subsection 8(p) of the OCS Lands
Act, which includes acreage within the area extending 3 nautical miles
seaward of State submerged lands. A qualified project is subject to
revenue sharing with those States that are eligible for revenue sharing
under Sec. 585.542. The entire area within a lease or grant for the
qualified project, excluding project easements, is considered the
qualified project area.

[[Page 593]]

Sec. 585.542 What makes a State eligible for payment of revenues?

A State is eligible for payment of revenues if any part of the
State's coastline is located within 15 miles of the announced geographic
center of the project area of a qualified project. A State is not
eligible for revenue sharing if all parts of that State's coastline are
more than 15 miles from the announced geographic center of the qualified
project area. This is the case even if the qualified project area is
located wholly or partially within an area extending 3 nautical miles
seaward of the submerged lands of that State or if there are no States
with a coastline less than 15 miles from the announced geographic center
of the qualified project area.

Sec. 585.543 Example of how the inverse distance formula works.

(a) Assume that the geographic center of the project area lies 12
miles from the closest coastline point of State A and 4 miles from the
closest coastline point of State B. BOEM will round dollar shares to the
nearest whole dollar. The proportional share due each State would be
calculated as follows:
(1) State A's share = [(\1/12\) / (\1/12\ + \1/4\)] = \1/4\.
(2) State B's share = [(\1/4\) / (\1/12\ + \1/4\)] = \3/4\.
(b) Therefore, State B would receive a share of revenues that is
three times as large as that awarded to State A, based on the finding
that State B's nearest coastline is one-third the distance to the
geographic center of the qualified project area as compared to State A's
nearest coastline. Eligible States share the 27 percent of the total
revenues from the qualified project as mandated under the OCS Lands Act.
Hence, if the qualified project generates $1,000,000 of Federal revenues
in a given year, the Federal Government would distribute the States' 27-
percent share as follows:
(1) State A's share = $270,000 x \1/4\ = $67,500.
(2) State B's share = $270,000 x \3/4\ = $202,500.

Subpart F_Plans and Information Requirements

Sec. 585.600 What plans and information must I submit to BOEM
before I conduct activities on my lease or grant?

You must submit a SAP, COP, or GAP and receive BOEM approval as set
forth in the following table:

------------------------------------------------------------------------
Before you: you must:
------------------------------------------------------------------------
(a) conduct any site assessment activities submit and obtain approval
on your commercial lease, for your SAP according to
Sec. Sec. 585.605
through 585.613.
(b) conduct any activities pertaining to submit and obtain approval
construction of facilities for commercial for your COP, according to
operations on your commercial lease, Sec. Sec. 585.620
through 585.629.
(c) conduct any activities on your limited submit and obtain approval
lease, ROW grant, or RUE grant in any OCS for your GAP according to
area, Sec. Sec. 585.640
through 585.648.
------------------------------------------------------------------------

Sec. 585.601 When am I required to submit my plans to BOEM?

You must submit your plans as follows:
(a) You may submit your SAP or GAP prior to lease or grant issuance,
but must submit your SAP or your GAP no later than 12 months from the
date of lease or grant issuance.
(b) If you intend to continue your commercial lease with an
operations term, you must submit a COP, or a FERC license application,
at least 6 months before the end of your site assessment term.
(c) You may submit your COP or FERC license application with your
SAP.
(1) You must provide sufficient data and information with your COP
for BOEM to complete the needed reviews and NEPA analysis; and
(2) BOEM may need to conduct additional reviews, including NEPA
analysis, if significant new information becomes available after you
complete your site assessment activities or you

[[Page 594]]

revise your COP. As a result of the additional reviews, we may require
modification of your COP.

[76 FR 64623, Oct. 18, 2011, as amended at 79 FR 21623, Apr. 17, 2014]

Sec. 585.602 What records must I maintain?

Until BOEM releases your financial assurance under Sec. 585.534,
you must maintain and provide to BOEM, upon request, all data and
information related to compliance with required terms and conditions of
your SAP, COP, or GAP.

Sec. Sec. 585.603-585.604 [Reserved]

Site Assessment Plan and Information Requirements for Commercial Leases

Sec. 585.605 What is a Site Assessment Plan (SAP)?

(a) A SAP describes the activities (e.g., installation of
meteorological towers, meteorological buoys) you plan to perform for the
characterization of your commercial lease, including your project
easement, or to test technology devices.
(1) Your SAP must describe how you will conduct your resource
assessment (e.g., meteorological and oceanographic data collection) or
technology testing activities; and
(2) BOEM will withhold trade secrets and commercial or financial
information that is privileged or confidential from public disclosure
under exemption 4 of the FOIA and as provided in Sec. 585.113.
(b) Your SAP must include data from:
(1) Physical characterization surveys (e.g., geological and
geophysical surveys or hazards surveys); and
(2) Baseline environmental surveys (e.g., biological or
archaeological surveys).
(c) You must receive BOEM approval of your SAP before you can begin
any of the approved activities on your lease, as provided in Sec.
585.613.
(d) If you propose to construct a facility or combination of
facilities deemed by BOEM to be complex or significant, as provided in
Sec. 585.613(a)(1), you must also comply with the requirements of
subpart G of this part and submit your Safety Management System as
required by Sec. 585.810.

Sec. 585.606 What must I demonstrate in my SAP?

(a) Your SAP must demonstrate that you have planned and are prepared
to conduct the proposed site assessment activities in a manner that
conforms to your responsibilities listed in Sec. 585.105(a) and:
(1) Conforms to all applicable laws, regulations, and lease
provisions of your commercial lease;
(2) Is safe;
(3) Does not unreasonably interfere with other uses of the OCS,
including those involved with National security or defense;
(4) Does not cause undue harm or damage to natural resources; life
(including human and wildlife); property; the marine, coastal, or human
environment; or sites, structures, or objects of historical or
archaeological significance;
(5) Uses best available and safest technology;
(6) Uses best management practices; and
(7) Uses properly trained personnel.
(b) You must also demonstrate that your site assessment activities
will collect the necessary information and data required for your COP,
as provided in Sec. 585.626(a).

Sec. 585.607 How do I submit my SAP?

You must submit one paper copy and one electronic version of your
SAP to BOEM at the address listed in Sec. 585.110(a).

Sec. Sec. 585.608-585.609 [Reserved]

Contents of the Site Assessment Plan

Sec. 585.610 What must I include in my SAP?

Your SAP must include the following information, as applicable.
(a) For all activities you propose to conduct under your SAP, you
must provide the following information:

[[Page 595]]

------------------------------------------------------------------------
Project information Including
------------------------------------------------------------------------
(1) Contact information................ The name, address, e-mail
address, and phone number of
an authorized representative.
(2) The site assessment or technology A discussion of the objectives;
testing concept. description of the proposed
activities, including the
technology you will use; and
proposed schedule from start
to completion.
(3) Designation of operator, if As provided in Sec. 585.405.
applicable.
(4) Commercial lease stipulations and A description of the measures
compliance. you took, or will take, to
satisfy the conditions of any
lease stipulations related to
your proposed activities.
(5) A location plat.................... The surface location and water
depth for all proposed and
existing structures,
facilities, and appurtenances
located both offshore and
onshore.
(6) General structural and project Information for each type of
design, fabrication, and installation. facility associated with your
project.
(7) Deployment activities.............. A description of the safety,
prevention, and environmental
protection features or
measures that you will use.
(8) Your proposed measures for A description of the measures
avoiding, minimizing, reducing, you will use to avoid or
eliminating, and monitoring minimize adverse effects and
environmental impacts. any potential incidental take,
before you conduct activities
on your lease, and how you
will mitigate environmental
impacts from your proposed
activities, including a
description of the measures
you will use as required by
subpart H of this part.
(9) CVA nomination, if required........ CVA nominations for reports in
subpart G of this part, as
required by Sec. 585.706, or
a request to waive the CVA
requirement, as required by
Sec. 585.705(c).
(10) Reference information............. A list of any document or
published source that you cite
as part of your plan. You may
reference information and data
discussed in other plans you
previously submitted or that
are otherwise readily
available to BOEM.
(11) Decommissioning and site clearance A discussion of methodologies.
procedures.
(12) Air quality information........... Information as described in
Sec. 585.659 of this
section.
(13) A listing of all Federal, State, A statement indicating whether
and local authorizations or approvals such authorization or approval
required to conduct site assessment has been applied for or
activities on your lease. obtained.
(14) A list of agencies and persons Contact information and issues
with whom you have communicated, or discussed.
with whom you will communicate,
regarding potential impacts associated
with your proposed activities.
(15) Financial assurance information... Statements attesting that the
activities and facilities
proposed in your SAP are or
will be covered by an
appropriate bond or other
approved security, as required
in Sec. Sec. 585.515 and
585.516.
(16) Other information................. Additional information as
requested by BOEM.
------------------------------------------------------------------------

(b) You must provide the results of geophysical and geological
surveys, hazards surveys, archaeological surveys (if required), and
baseline collection studies (e.g., biological) with the supporting data
in your SAP:

------------------------------------------------------------------------
Information Report contents Including
------------------------------------------------------------------------
(1) Geotechnical............ The results from the A description of all
geotechnical survey relevant seabed and
with supporting engineering data
data. and information to
allow for the
design of the
foundation for that
facility. You must
provide data and
information to
depths below which
the underlying
conditions will not
influence the
integrity or
performance of the
structure. This
could include a
series of sampling
locations (borings
and in situ tests)
as well as
laboratory testing
of soil samples,
but may consist of
a minimum of one
deep boring with
samples.
(2) Shallow hazards......... The results from the A description of
shallow hazards information
survey with sufficient to
supporting data. determine the
presence of the
following features
and their likely
effects on your
proposed facility,
including:
(i) Shallow faults;
(ii) Gas seeps or
shallow gas;
(ii) Slump blocks or
slump sediments;
(iv) Hydrates; and
(v) Ice scour of
seabed sediments.

[[Page 596]]

(3) Archaeological resources The results from the (i) A description
archaeological of the results
survey with and data from
supporting data, if the
required. archaeological
survey;
(ii) A
description of
the historic and
prehistoric
archaeological
resources, as
required by the
National
Historic
Preservation Act
(NHPA) of 1966,
as amended.
(4) Geological survey....... The results from the A report that
geological survey describes the
with supporting results of a
data. geological survey
that includes
descriptions of:
(i) Seismic activity
at your proposed
site;
(ii) Fault zones;
(iii) The
possibility and
effects of seabed
subsidence; and
(iv) The extent and
geometry of
faulting
attenuation effects
of geologic
conditions near
your site.
(5) Biological survey....... The results from the A description of the
biological survey results of a
with supporting biological survey,
data. including
descriptions of the
presence of live
bottoms; hard
bottoms;
topographic
features; and
surveys of other
marine resources
such as fish
populations
(including
migratory
populations),
marine mammals, sea
turtles, and sea
birds.
------------------------------------------------------------------------

(c) If you submit your COP or FERC license application with your SAP
then:
(1) You must provide sufficient data and information with your COP
or FERC license application for BOEM and/or FERC to complete the needed
reviews and NEPA analysis.
(2) You may need to revise your COP or FERC license application and
BOEM and/or FERC may need to conduct additional reviews, including NEPA
analysis, if new information becomes available after you complete your
site assessment activities.

Sec. 585.611 What information and certifications must I submit
with my SAP to assist BOEM in complying with NEPA and other relevant laws?

You must submit, with your SAP, detailed information to assist BOEM
in complying with NEPA and other relevant laws as appropriate.
(a) A SAP submitted for an area in which BOEM has not previously
reviewed site assessment activities under NEPA or other applicable
Federal laws, must describe those resources, conditions, and activities
listed in the following table that could be affected by your proposed
activities or that could affect the activities proposed in your SAP.
(b) For a SAP submitted for an area in which BOEM has previously
considered site assessment activities under applicable Federal law
(e.g., a NEPA analysis and CZMA consistency determination for site
assessment activities), BOEM will review the SAP to determine if its
impacts are consistent with those previously considered. If the
anticipated effects of your proposed SAP activities are significantly
different than those previously anticipated, we may determine that
additional NEPA and other relevant Federal reviews are required. In that
case, BOEM will notify you of such determination, and you must submit a
SAP that describes those resources, conditions, and activities listed in
the following table that could be affected by your proposed activities
or that could affect the activities proposed in your SAP, including:

[[Page 597]]

(5) Sensitive biological resources Essential fish habitat, refuges,
or habitats. preserves, special management areas
identified in coastal management
programs, sanctuaries, rookeries,
hard bottom habitat, chemosynthetic
communities, calving grounds,
barrier islands, beaches, dunes,
and wetlands.
(6) Archaeological resources...... As required by the NHPA (16 U.S.C.
470 et seq.), as amended.
(7) Social and economic conditions Employment, existing offshore and
coastal infrastructure (including
major sources of supplies,
services, energy, and water), land
use, subsistence resources and
harvest practices, recreation,
recreational and commercial fishing
(including typical fishing seasons,
location, and type), minority and
lower income groups, coastal zone
management programs, and viewshed.
(8) Coastal and marine uses....... Military activities, vessel traffic,
and energy and nonenergy mineral
exploration or development.
(9) Consistency Certification..... If required by CZMA, as appropriate:
(i) 15 CFR part 930, subpart D, if
the SAP is submitted prior to lease
issuance; (ii) 15 CFR part 930,
subpart E, if the SAP is submitted
after lease issuance.
------------------------------------------------------------------------
(10) Other resources, conditions, As identified by BOEM.
and activities.
------------------------------------------------------------------------

[79 FR 21623, Apr. 17, 2014]

Sec. 585.612 How will my SAP be processed for Federal consistency
under the Coastal Zone Management Act?

Your SAP will be processed based on whether it is submitted before
or after your lease is issued:

------------------------------------------------------------------------
Consistency review of your SAP will
If your SAP is submitted: be handled as follows:
------------------------------------------------------------------------
(a) Before lease issuance......... You will furnish a copy of your SAP,
consistency certification, and
necessary data and information
pursuant to 15 CFR part 930,
subpart D, to the applicable State
CZMA agency or agencies and BOEM at
the same time.
(b) After lease issuance.......... You will submit a copy of your SAP,
consistency certification, and
necessary data and information
pursuant to 15 CFR part 930,
subpart E to BOEM. BOEM will
forward to the applicable State
CZMA agency or agencies one paper
copy and one electronic copy of
your SAP, consistency
certification, and necessary data
and information required under 15
CFR part 930, subpart E, after BOEM
has determined that all information
requirements for the SAP are met.
------------------------------------------------------------------------

[79 FR 21624, Apr. 17, 2014]

Sec. 585.613 How will BOEM process my SAP?

(a) BOEM will review your submitted SAP, and additional information
provided pursuant to Sec. 585.611, to determine if it contains the
information necessary to conduct our technical and environmental
reviews.
(1) We will notify you if we deem your proposed facility or
combination of facilities to be complex or significant;
(2) We will notify you if your submitted SAP lacks any necessary
information;
(b) BOEM will prepare NEPA analysis, as appropriate.
(c) As appropriate, we will coordinate and consult with relevant
Federal and State agencies, executives of relevant local governments,
and affected Indian Tribes and will provide to other Federal, State, and
local agencies and affected Indian Tribes relevant nonproprietary data
and information pertaining to your proposed activities.
(d) During the review process, we may request additional information
if we determine that the information provided is not sufficient to
complete the review and approval process. If you fail to provide the
requested information, BOEM may disapprove your SAP.
(e) Upon completion of our technical and environmental reviews and
other reviews required by Federal laws (e.g., CZMA), BOEM may approve,
disapprove, or approve with modifications your SAP.
(1) If we approve your SAP, we will specify terms and conditions to
be incorporated into your SAP. You must certify compliance with those
terms

[[Page 598]]

and conditions required under Sec. 585.615(c); and
(2) If we disapprove your SAP, we will inform you of the reasons and
allow you an opportunity to submit a revised plan making the necessary
corrections, and may suspend the term of your lease, as appropriate, to
allow this to occur.

Activities Under an Approved SAP

Sec. 585.614 When may I begin conducting activities under my approved SAP?

(a) You may begin conducting the activities approved in your SAP
following BOEM approval of your SAP.
(b) If you are installing a facility or a combination of facilities
deemed by BOEM to be complex or significant, as provided in Sec.
585.613(a)(1), you must comply with the requirements of subpart G of
this part and submit your Safety Management System required by Sec.
585.810 before construction may begin.

Sec. 585.615 What other reports or notices must I submit to BOEM
under my approved SAP?

(a) You must notify BOEM in writing within 30 days of completing
installation activities approved in your SAP.
(b) You must prepare and submit to BOEM a report annually on
November 1 of each year that summarizes your site assessment activities
and the results of those activities. BOEM will withhold trade secrets
and commercial or financial information that is privileged or
confidential from public disclosure under exemption 4 of the FOIA and as
provided in Sec. 585.113.
(c) You must submit a certification of compliance annually (or other
frequency as determined by BOEM) with certain terms and conditions of
your SAP that BOEM identifies under Sec. 585.613(e)(1). Together with
your certification, you must submit:
(1) Summary reports that show compliance with the terms and
conditions which require certification; and
(2) A statement identifying and describing any mitigation measures
and monitoring methods and their effectiveness. If you identified
measures that were not effective, you must include your recommendations
for new mitigation measures or monitoring methods.

Sec. 585.616 [Reserved]

Sec. 585.617 What activities require a revision to my SAP,
and when will BOEM approve the revision?

(a) You must notify BOEM in writing before conducting any activities
not described in your approved SAP, describing in detail the type of
activities you propose to conduct. We will determine whether the
activities you propose are authorized by your existing SAP or require a
revision to your SAP. We may request additional information from you, if
necessary, to make this determination.
(b) BOEM will periodically review the activities conducted under an
approved SAP. The frequency and extent of the review will be based on
the significance of any changes in available information and on onshore
or offshore conditions affecting, or affected by, the activities
conducted under your SAP. If the review indicates that the SAP should be
revised to meet the requirements of this part, we will require you to
submit the needed revisions.
(c) Activities for which a proposed revision to your SAP will likely
be necessary include:
(1) Activities not described in your approved SAP;
(2) Modifications to the size or type of facility or equipment you
will use;
(3) Changes in the surface location of a facility or structure;
(4) Addition of a facility or structure not contemplated in your
approved SAP;
(5) Changes in the location of your onshore support base from one
State to another, or to a new base requiring expansion;
(6) Changes in the location of bottom disturbances (anchors, chains,
etc.) by 500 feet (152 meters) or greater from the approved locations.
If a specific anchor pattern was approved as a mitigation measure to
avoid contact with bottom features, any change in the proposed bottom
disturbances would likely trigger the need for a revision;
(7) Structural failure of one or more facilities; or
(8) Changes to any other activity specified by BOEM.

[[Page 599]]

(d) We may begin the appropriate NEPA analysis and other relevant
consultations when we determine that a proposed revision could:
(1) Result in a significant change in the impacts previously
identified and evaluated;
(2) Require any additional Federal authorizations; or
(3) Involve activities not previously identified and evaluated.
(e) When you propose a revision, we may approve the revision if we
determine that the revision is:
(1) Designed not to cause undue harm or damage to natural resources;
life (including human and wildlife); property; the marine, coastal, or
human environment; or sites, structures, or objects of historical or
archaeological significance; and
(2) Otherwise consistent with the provisions of subsection 8(p) of
the OCS Lands Act.

Sec. 585.618 What must I do upon completion of approved
site assessment activities?

(a) If, prior to the expiration of your site assessment term, you
timely submit a COP meeting the requirements of this subpart, or a
complete FERC license application, that describes the continued use of
existing facilities approved in your SAP, you may keep such facilities
in place on your lease during the time that BOEM reviews your COP for
approval or FERC reviews your license application for approval.
(b) You are not required to initiate the decommissioning process for
facilities that are authorized to remain in place under your approved
COP or approved FERC license.
(c) If, following the technical and environmental review of your
submitted COP, BOEM determines that such facilities may not remain in
place, you must initiate the decommissioning process, as provided in
subpart I of this part.
(d) If FERC determines that such facilities may not remain in place,
you must initiate the decommissioning process as provided in subpart I
of this part.
(e) You must initiate the decommissioning process, as set forth in
subpart I of this part, upon the termination of your lease.

Sec. 585.619 [Reserved]

Construction and Operations Plan for Commercial Leases

Sec. 585.620 What is a Construction and Operations Plan (COP)?

The COP describes your construction, operations, and conceptual
decommissioning plans under your commercial lease, including your
project easement. BOEM will withhold trade secrets and commercial or
financial information that is privileged or confidential from public
disclosure under exemption 4 of the FOIA and in accordance with the
terms of Sec. 585.113.
(a) Your COP must describe all planned facilities that you will
construct and use for your project, including onshore and support
facilities and all anticipated project easements.
(b) Your COP must describe all proposed activities including your
proposed construction activities, commercial operations, and conceptual
decommissioning plans for all planned facilities, including onshore and
support facilities.
(c) You must receive BOEM approval of your COP before you can begin
any of the approved activities on your lease.

Sec. 585.621 What must I demonstrate in my COP?

Your COP must demonstrate that you have planned and are prepared to
conduct the proposed activities in a manner that conforms to your
responsibilities listed in Sec. 585.105(a) and:
(a) Conforms to all applicable laws, implementing regulations, lease
provisions, and stipulations or conditions of your commercial lease;
(b) Is safe;
(c) Does not unreasonably interfere with other uses of the OCS,
including those involved with National security or defense;
(d) Does not cause undue harm or damage to natural resources; life
(including human and wildlife); property; the marine, coastal, or human
environment; or sites, structures, or objects of historical or
archaeological significance;

[[Page 600]]

(e) Uses best available and safest technology;
(f) Uses best management practices; and
(g) Uses properly trained personnel.

Sec. 585.622 How do I submit my COP?

(a) You must submit one paper copy and one electronic version of
your COP to BOEM at the address listed in Sec. 585.110(a).
(b) You may submit information and a request for any project
easement as part of your original COP submission or as a revision to
your COP.

Sec. Sec. 585.623-585.625 [Reserved]

Contents of the Construction and Operations Plan

Sec. 585.626 What must I include in my COP?

(a) You must submit the results of the following surveys for the
proposed site(s) of your facility(ies). Your COP must include the
following information:

------------------------------------------------------------------------
Information: Report contents: Including:
------------------------------------------------------------------------
(1) Shallow hazards......... The results of the Information
shallow hazards sufficient to
survey with determine the
supporting data. presence of the
following features
and their likely
effects on your
proposed facility,
including:
(i) Shallow
faults;
(ii) Gas seeps or
shallow gas;
(iii) Slump
blocks or slump
sediments;
(iv) Hydrates; or
(v) Ice scour of
seabed
sediments.
(2) Geological survey The results of the Assessment of:
relevant to the design and geological survey (i) Seismic activity
siting of your facility. with supporting at your proposed
data. site;
(ii) Fault zones;
(iii) The
possibility and
effects of seabed
subsidence; and
(iv) The extent and
geometry of
faulting
attenuation effects
of geologic
conditions near
your site.
(3) Biological.............. The results of the A description of the
biological survey results of
with supporting biological surveys
data. used to determine
the presence of
live bottoms, hard
bottoms, and
topographic
features, and
surveys of other
marine resources
such as fish
populations
(including
migratory
populations),
marine mammals, sea
turtles, and sea
birds.
(4) Geotechnical survey..... The results of your (i) The results of a
sediment testing testing program
program with used to investigate
supporting data, the stratigraphic
the various field and engineering
and laboratory test properties of the
methods employed, sediment that may
and the affect the
applicability of foundations or
these methods as anchoring systems
they pertain to the for your facility.
quality of the (ii) The results of
samples, the type adequate in situ
of sediment, and testing, boring,
the anticipated and sampling at
design application. each foundation
You must explain location, to
how the engineering examine all
properties of each important sediment
sediment stratum and rock strata to
affect the design determine its
of your facility. strength
In your classification,
explanation, you deformation
must describe the properties, and
uncertainties dynamic
inherent in your characteristics.
overall testing (iii) The results of
program, and the a minimum of one
reliability and deep boring (with
applicability of soil sampling and
each test method. testing) at each
edge of the project
area and within the
project area as
needed to determine
the vertical and
lateral variation
in seabed
conditions and to
provide the
relevant
geotechnical data
required for
design.
(5) Archaeological resources The results of the A description of the
archaeological historic and
resource survey prehistoric
with supporting archaeological
data. resources, as
required by the
NHPA (16 U.S.C. 470
et. seq.), as
amended.
(6) Overall site An overall site An analysis of the
investigation. investigation potential for:
report for your (i) Scouring of the
facility that seabed;
integrates the (ii) Hydraulic
findings of your instability;
shallow hazards (iii) The occurrence
surveys and of sand waves;
geologic surveys, (iv) Instability of
and, if required, slopes at the
your subsurface facility location;
surveys with (v) Liquefaction, or
supporting data. possible reduction
of sediment
strength due to
increased pore
pressures;
(vi) Degradation
of subsea
permafrost
layers;

[[Page 601]]

(vii) Cyclic
loading;
(viii) Lateral
loading;
(ix) Dynamic
loading;
(x) Settlements
and
displacements;
(xi) Plastic
deformation and
formation
collapse
mechanisms; and
(xii) Sediment
reactions on the
facility
foundations or
anchoring
systems.
------------------------------------------------------------------------

(b) Your COP must include the following project-specific
information, as applicable.

------------------------------------------------------------------------
Project information: Including:
------------------------------------------------------------------------
(1) Contact information................ The name, address, e-mail
address, and phone number of
an authorized representative.
(2) Designation of operator, if As provided in Sec. 585.405.
applicable.
(3) The construction and operation A discussion of the objectives,
concept. description of the proposed
activities, tentative schedule
from start to completion, and
plans for phased development,
as provided in Sec. 585.629.
(4) Commercial lease stipulations and A description of the measures
compliance. you took, or will take, to
satisfy the conditions of any
lease stipulations related to
your proposed activities.
(5) A location plat.................... The surface location and water
depth for all proposed and
existing structures,
facilities, and appurtenances
located both offshore and
onshore, including all anchor/
mooring data.
(6) General structural and project Information for each type of
design, fabrication, and installation. structure associated with your
project and, unless BOEM
provides otherwise, how you
will use a CVA to review and
verify each stage of the
project.
(7) All cables and pipelines, including Location, design and
cables on project easements. installation methods, testing,
maintenance, repair, safety
devices, exterior corrosion
protection, inspections, and
decommissioning.
(8) A description of the deployment Safety, prevention, and
activities. environmental protection
features or measures that you
will use.
(9) A list of solid and liquid wastes Disposal methods and locations.
generated.
(10) A listing of chemical products A list of chemical products
used (if stored volume exceeds used; the volume stored on
Environmental Protection Agency (EPA) location; their treatment,
Reportable Quantities). discharge, or disposal methods
used; and the name and
location of the onshore waste
receiving, treatment, and/or
disposal facility. A
description of how these
products would be brought
onsite, the number of
transfers that may take place,
and the quantity that that
will be transferred each time.
(11) A description of any vessels, An estimate of the frequency
vehicles, and aircraft you will use to and duration of vessel/vehicle/
support your activities. aircraft traffic.
(12) A general description of the (i) Under normal conditions.
operating procedures and systems. (ii) In the case of accidents
or emergencies, including
those that are natural or
manmade.
(13) Decommissioning and site clearance A discussion of general
procedures. concepts and methodologies.
(14) A listing of all Federal, State, (i) The U.S. Coast Guard, U.S.
and local authorizations, approvals, Army Corps Of Engineers, and
or permits that are required to any other applicable
conduct the proposed activities, authorizations, approvals, or
including commercial operations. permits, including any
Federal, State or local
authorizations pertaining to
energy gathering, transmission
or distribution (e.g.,
interconnection
authorizations).
(ii) A statement indicating
whether you have applied for
or obtained such
authorization, approval, or
permit.
(15) Your proposed measures for A description of the measures
avoiding, minimizing, reducing, you will use to avoid or
eliminating, and monitoring minimize adverse effects and
environmental impacts. any potential incidental take
before you conduct activities
on your lease, and how you
will mitigate environmental
impacts from your proposed
activities, including a
description of the measures
you will use as required by
subpart H of this part.
(16) Information you incorporate by A listing of the documents you
reference. referenced.
(17) A list of agencies and persons Contact information and issues
with whom you have communicated, or discussed.
with whom you will communicate,
regarding potential impacts associated
with your proposed activities.
(18) Reference......................... A list of any document or
published source that you cite
as part of your plan. You may
reference information and data
discussed in other plans you
previously submitted or that
are otherwise readily
available to BOEM.
(19) Financial assurance............... Statements attesting that the
activities and facilities
proposed in your COP are or
will be covered by an
appropriate bond or security,
as required by Sec. Sec.
585.515 and 585.516.

[[Page 602]]

(20) CVA nominations for reports CVA nominations for reports in
required in subpart G of this part. subpart G of this part, as
required by Sec. 585.706, or
a request for a waiver under
Sec. 585.705(c).
(21) Construction schedule............. A reasonable schedule of
construction activity showing
significant milestones leading
to the commencement of
commercial operations.
(22) Air quality information........... As described in Sec. 585.659
of this section.
(23) Other information................. Additional information as
required by BOEM.
------------------------------------------------------------------------

Sec. 585.627 What information and certifications must I submit with my COP
to assist the BOEM in complying with NEPA and other relevant laws?

(a) You must submit with your COP detailed information to assist
BOEM in complying with NEPA and other relevant laws. Your COP must
describe those resources, conditions, and activities listed in the
following table that could be affected by your proposed activities, or
that could affect the activities proposed in your COP, including:

------------------------------------------------------------------------
Type of information: Including:
------------------------------------------------------------------------
(1) Hazard information............ Meteorology, oceanography, sediment
transport, geology, and shallow
geological or manmade hazards.
(2) Water quality................. Turbidity and total suspended solids
from construction.
(3) Biological resources.......... Benthic communities, marine mammals,
sea turtles, coastal and marine
birds, fish and shellfish,
plankton, seagrasses, and plant
life.
(4) Threatened or endangered As defined by the ESA (16 U.S.C.
species. 1531 et seq.).
(5) Sensitive biological resources Essential fish habitat, refuges,
or habitats. preserves, special management areas
identified in coastal management
programs, sanctuaries, rookeries,
hard bottom habitat, chemosynthetic
communities, calving grounds,
barrier islands, beaches, dunes,
and wetlands.
(6) Archaeological resources...... As required by the NHPA (16 U.S.C.
470 et seq.), as amended.
(7) Social and economic resources. Employment, existing offshore and
coastal infrastructure (including
major sources of supplies,
services, energy, and water), land
use, subsistence resources and
harvest practices, recreation,
recreational and commercial fishing
(including typical fishing seasons,
location, and type), minority and
lower income groups, coastal zone
management programs, and viewshed.
(8) Coastal and marine uses....... Military activities, vessel traffic,
and energy and nonenergy mineral
exploration or development.
(9) Consistency Certification..... As required by the CZMA regulations:
(i) 15 CFR part 930, subpart D, if
your COP is submitted before lease
issuance.
(ii) 15 CFR part 930, subpart E, if
your COP is submitted after lease
issuance.
(10) Other resources, conditions, As identified by BOEM.
and activities.
------------------------------------------------------------------------

(b) You must submit one paper copy and one electronic copy of your
consistency certification. Your consistency certification must include:
(1) One copy of your consistency certification under either
subsection 307(c)(3)(B) of the CZMA (16 U.S.C. 1456(c)(3)(B)) and 15 CFR
930.76 or subsection 307(c)(3)(A) of the CZMA (16 U.S.C. 1456(c)(3)(A))
and 15 CFR 930.57, stating that the proposed activities described in
detail in your plans comply with the State(s) approved coastal
management program(s) and will be conducted in a manner that is
consistent with such program(s); and
(2) ``Necessary data and information,'' as required by 15 CFR
930.58.
(c) You must submit your oil spill response plan, as required by 30
CFR part 254.
(d) You must submit your Safety Management System as required by
Sec. 585.810.

[76 FR 64623, Oct. 18, 2011, as amended at 79 FR 21624, Apr. 17, 2014]

Sec. 585.628 How will BOEM process my COP?

(a) BOEM will review your submitted COP, and the information
provided pursuant to Sec. 585.627, to determine if it contains all the
required information necessary to conduct our technical and
environmental reviews. We will notify you if your submitted COP lacks
any necessary information.

[[Page 603]]

(b) BOEM will prepare an appropriate NEPA analysis.
(c) If your COP is submitted after lease issuance, BOEM will forward
one copy of your COP, consistency certification, and associated data and
information under the CZMA to the applicable State CZMA agency or
agencies after all information requirements for the COP are met.
(d) As appropriate, BOEM will coordinate and consult with relevant
Federal, State, and local agencies and affected Indian Tribes, and
provide to them relevant nonproprietary data and information pertaining
to your proposed activities.
(e) During the review process, we may request additional information
if we determine that the information provided is not sufficient to
complete the review and approval process. If you fail to provide the
requested information, BOEM may disapprove your COP.
(f) Upon completion of our technical and environmental reviews and
other reviews required by Federal law (e.g., CZMA), BOEM may approve,
disapprove, or approve with modifications your COP.
(1) If we approve your COP, we will specify terms and conditions to
be incorporated into your COP. You must certify compliance with certain
of those terms and conditions, as required under Sec. 585.633(b); and
(2) If we disapprove your COP, we will inform you of the reasons and
allow you an opportunity to resubmit a revised plan addressing the
concerns identified, and may suspend the term of your lease, as
appropriate, to allow this to occur.
(g) If BOEM approves your project easement, BOEM will issue an
addendum to your lease specifying the terms of the project easement. A
project easement may include off-lease areas that:
(1) Contain the sites on which cable, pipeline, or associated
facilities are located;
(2) Do not exceed 200 feet (61 meters) in width, unless safety and
environmental factors during construction and maintenance of the
associated cables or pipelines require a greater width; and
(3) For associated facilities, are limited to the area reasonably
necessary for power or pumping stations or other accessory facilities.

[76 FR 64623, Oct. 18, 2011, as amended at 79 FR 21625, Apr. 17, 2014]

Sec. 585.629 May I develop my lease in phases?

In your COP, you may request development of your commercial lease in
phases. In support of your request, you must provide details as to what
portions of the lease will be initially developed for commercial
operations and what portions of the lease will be reserved for
subsequent phased development.

Sec. 585.630 [Reserved]

Activities Under an Approved COP

Sec. 585.631 When must I initiate activities under an approved COP?

After your COP is approved, you must commence construction by the
date given in the construction schedule required by Sec.
585.626(b)(21), and included as a part of your approved COP, unless BOEM
approves a deviation from your schedule.

Sec. 585.632 What documents must I submit before I may construct
and install facilities under my approved COP?

(a) You must submit to BOEM the documents listed in the following
table:

------------------------------------------------------------------------
Requirements are
Document: found in:
------------------------------------------------------------------------
(1) Facility Design Report........................... Sec. 585.701
(2) Fabrication and Installation Report.............. Sec. 585.702
------------------------------------------------------------------------

(b) You must submit your Safety Management System, as required by
Sec. 585.810 of this part.
(c) These activities must fall within the scope of your approved
COP. If they do not fall within the scope of your approved COP, you will
be required to submit a revision to your COP, under Sec. 585.634, for
BOEM approval before commencing the activity.

Sec. 585.633 How do I comply with my COP?

(a) Based on BOEM's environmental and technical reviews, we will
specify

[[Page 604]]

terms and conditions to be incorporated into your COP.
(b) You must submit a certification of compliance annually (or other
frequency as determined by BOEM) with certain terms and conditions of
your COP that BOEM identifies. Together with your certification, you
must submit:
(1) Summary reports that show compliance with the terms and
conditions which require certification; and
(2) A statement identifying and describing any mitigation measures
and monitoring methods, and their effectiveness. If you identified
measures that were not effective, then you must make recommendations for
new mitigation measures or monitoring methods.
(c) As provided at Sec. 585.105(i), BOEM may require you to submit
any supporting data and information.

Sec. 585.634 What activities require a revision to my COP,
and when will BOEM approve the revision?

(a) You must notify BOEM in writing before conducting any activities
not described in your approved COP, describing in detail the type of
activities you propose to conduct. We will determine whether the
activities you propose are authorized by your existing COP or require a
revision to your COP. We may request additional information from you, if
necessary, to make this determination.
(b) BOEM will periodically review the activities conducted under an
approved COP. The frequency and extent of the review will be based on
the significance of any changes in available information, and on onshore
or offshore conditions affecting, or affected by, the activities
conducted under your COP. If the review indicates that the COP should be
revised to meet the requirement of this part, we will require you to
submit the needed revisions.
(c) Activities for which a proposed revision to your COP will likely
be necessary include:
(1) Activities not described in your approved COP;
(2) Modifications to the size or type of facility or equipment you
will use;
(3) Change in the surface location of a facility or structure;
(4) Addition of a facility or structure not described in your
approved COP;
(5) Change in the location of your onshore support base from one
State to another or to a new base requiring expansion;
(6) Changes in the location of bottom disturbances (anchors, chains,
etc.) by 500 feet (152 meters) or greater from the approved locations
(e.g., if a specific anchor pattern was approved as a mitigation measure
to avoid contact with bottom features, any change in the proposed bottom
disturbances would likely trigger the need for a revision);
(7) Structural failure of one or more facilities; or
(8) Change in any other activity specified by BOEM.
(d) We may begin the appropriate NEPA analysis and relevant
consultations when we determine that a proposed revision could:
(1) Result in a significant change in the impacts previously
identified and evaluated;
(2) Require any additional Federal authorizations; or
(3) Involve activities not previously identified and evaluated.
(e) When you propose a revision, we may approve the revision if we
determine that the revision is:
(1) Designed not to cause undue harm or damage to natural resources;
life (including human and wildlife); property; the marine, coastal, or
human environment; or sites, structures, or objects of historical or
archaeological significance; and
(2) Otherwise consistent with the provisions of subsection 8(p) of
the OCS Lands Act.

Sec. 585.635 What must I do if I cease activities approved in my COP
before the end of my commercial lease?

You must notify the BOEM, within 5 business days, any time you cease
commercial operations, without an approved suspension, under your
approved COP. If you cease commercial operations for an indefinite
period which extends longer than 6 months, we may cancel your lease
under Sec. 585.437 and, you must initiate the decommissioning process
as set forth in subpart I of this part.

[[Page 605]]

Sec. 585.636 What notices must I provide BOEM following approval of my COP?

You must notify BOEM in writing of the following events, within the
time periods provided:
(a) No later than 30 days after commencing activities associated
with the placement of facilities on the lease area under a Fabrication
and Installation Report.
(b) No later than 30 days after completion of construction and
installation activities under a Fabrication and Installation Report.
(c) At least 7 days before commencing commercial operations.

Sec. 585.637 When may I commence commercial operations
on my commercial lease?

If you are conducting activities on your lease that:
(a) Do not require a FERC license (i.e., wind), then you may
commence commercial operations 30 days after the CVA or project engineer
has submitted to BOEM the final Fabrication and Installation Report for
the fabrication and installation review, as provided in Sec. 585.708.
(b) Require a FERC license or exemption, then you may commence
commercial operations when permitted by the terms of your license or
exemption.

Sec. 585.638 What must I do upon completion of my commercial operations
as approved in my COP or FERC license?

(a) Upon completion of your approved activities under your COP, you
must initiate the decommissioning process as set forth in subpart I of
this part. You must submit your decommissioning application as provided
in Sec. Sec. 585.905 and 585.906.
(b) Upon completion of your approved activities under your FERC
license, the terms of your FERC license will govern your decommissioning
activities.

Sec. 585.639 [Reserved]

General Activities Plan Requirements For Limited Leases, ROW Grants, and
RUE Grants

Sec. 585.640 What is a General Activities Plan (GAP)?

(a) A GAP describes your proposed construction, activities, and
conceptual decommissioning plans for all planned facilities, including
testing of technology devices and onshore and support facilities that
you will construct and use for your project, including any project
easements for the assessment and development of your limited lease or
grant.
(b) You must receive BOEM approval of your GAP before you can begin
any of the approved activities on your lease or grant. You must submit
your GAP no later than 12 months from the date of the lease or grant
issuance.

[76 FR 64623, Oct. 18, 2011, as amended at 79 FR 21625, Apr. 17, 2014]

Sec. 585.641 What must I demonstrate in my GAP?

Your GAP must demonstrate that you have planned and are prepared to
conduct the proposed activities in a manner that:
(a) Conforms to all applicable laws, implementing regulations, lease
provisions and stipulations;
(b) Is safe;
(c) Does not unreasonably interfere with other uses of the OCS,
including those involved with National security or defense;
(d) Does not cause undue harm or damage to natural resources; life
(including human and wildlife); property; the marine, coastal, or human
environment; or sites, structures, or objects of historical or
archaeological significance;
(e) Uses best available and safest technology;
(f) Uses best management practices; and
(g) Uses properly trained personnel.

Sec. 585.642 How do I submit my GAP?

(a) You must submit one paper copy and one electronic version of
your GAP to BOEM at the address listed in Sec. 585.110(a).

[[Page 606]]

(b) If you have a limited lease, you may submit information on any
project easement as part of your original GAP submission or as a
revision to your GAP.

Sec. Sec. 585.643-585.644 [Reserved]

Contents of the General Activities Plan

Sec. 585.645 What must I include in my GAP?

(a) You must provide the following results of geophysical and
geological surveys, hazards surveys, archaeological surveys (if
required), and baseline collection studies (e.g., biological) with the
supporting data in your GAP:

(b) For all activities you propose to conduct under your GAP, you
must provide the following information:

[[Page 607]]

(5) A location plat.................... The surface location and water
depth for all proposed and
existing structures,
facilities, and appurtenances
located both offshore and
onshore.
(6) General structural and project Information for each type of
design, fabrication, and installation. facility associated with your
project.
(7) Deployment activities.............. A description of the safety,
prevention, and environmental
protection features or
measures that you will use.
(8) A list of solid and liquid wastes Disposal methods and locations.
generated.
(9) A listing of chemical products used A list of chemical products
(only if stored volume exceeds USEPA used; the volume stored on
Reportable Quantities). location; their treatment,
discharge, or disposal methods
used; and the name and
location of the onshore waste
receiving, treatment, and/or
disposal facility. A
description of how these
products would be brought
onsite, the number of
transfers that may take place,
and the quantity that will be
transferred each time.
(10) Reference information............. A list of any document or
published source that you cite
as part of your plan. You may
reference information and data
discussed in other plans you
previously submitted or that
are otherwise readily
available to BOEM.
(11) Decommissioning and site clearance A discussion of methodologies.
procedures.
(12) Air quality information........... As described in Sec. 585.659
of this section.
(13) A listing of all Federal, State, A statement indicating whether
and local authorizations or approvals such authorization or approval
required to conduct site assessment has been applied for or
activities on your lease. obtained.
(14) A list of agencies and persons Contact information and issues
with whom you have communicated, or discussed.
with whom you will communicate,
regarding potential impacts associated
with your proposed activities.
(15) Financial assurance information... Statements attesting that the
activities and facilities
proposed in your GAP are or
will be covered by an
appropriate bond or other
approved security, as required
in Sec. Sec. 585.520 and
585.521.
(16) Other information................. Additional information as
requested by BOEM.
------------------------------------------------------------------------

(c) If you are applying for a project easement or constructing a
facility, or a combination of facilities deemed by BOEM to be complex or
significant, you must provide the following information in addition to
what is required in paragraphs (a) and (b) of this section and comply
with the requirements of subpart G of this part:

------------------------------------------------------------------------
Project information: Including:
------------------------------------------------------------------------
(1) The construction and operation A discussion of the objectives,
concept. description of the proposed
activities, and tentative
schedule from start to
completion.
(2) All cables and pipelines, including The location, design,
cables on project easements. installation methods, testing,
maintenance, repair, safety
devices, exterior corrosion
protection, inspections, and
decommissioning.
(3) A description of the deployment Safety, prevention, and
activities. environmental protection
features or measures that you
will use.
(4) A general description of the (i) Under normal conditions.
operating procedures and systems. (ii) In the case of accidents
or emergencies, including
those that are natural or
manmade.
(5) CVA nominations for reports CVA nominations for reports in
required in subpart G of this part. subpart G of this part, as
required by Sec. 585.706, or
a request for a waiver under
Sec. 585.705(c).
(6) Construction schedule.............. A reasonable schedule of
construction activity showing
significant milestones leading
to the commencement of
activities.
(7) Other information.................. Additional information as
required by the BOEM.
------------------------------------------------------------------------

(d) BOEM will withhold trade secrets and commercial or financial
information that is privileged or confidential from public disclosure in
accordance with the terms of Sec. 585.113.

Sec. 585.646 What information and certifications must I submit with my GAP
to assist BOEM in complying with NEPA and other relevant laws?

You must submit, with your GAP, detailed information to assist BOEM
in

[[Page 608]]

complying with NEPA and other relevant laws as appropriate.
(a) A GAP submitted for an area in which BOEM has not reviewed GAP
activities under NEPA or other applicable Federal laws must describe
those resources, conditions, and activities listed in the following
table that could be affected by your proposed activities or that could
affect the activities proposed in your GAP.
(b) For a GAP submitted for an area in which BOEM has considered GAP
activities under applicable Federal law (e.g., a NEPA analysis and CZMA
consistency determination for the GAP activities), BOEM will review the
GAP to determine if its impacts are consistent with those previously
considered. If the anticipated effects of your proposed GAP activities
are significantly different than those previously anticipated, we may
determine that additional NEPA and other relevant Federal reviews are
required. In that case, BOEM will notify you of such determination, and
you must submit a GAP that describes those resources, conditions, and
activities listed in the following table that could be affected by your
proposed activities or that could affect the activities proposed in your
GAP, including:

------------------------------------------------------------------------
Type of information: Including:
------------------------------------------------------------------------
(1) Hazard information............ Meteorology, oceanography, sediment
transport, geology, and shallow
geological or manmade hazards.
(2) Water quality................. Turbidity and total suspended solids
from construction.
(3) Biological resources.......... Benthic communities, marine mammals,
sea turtles, coastal and marine
birds, fish and shellfish,
plankton, sea grasses, and other
plant life.
(4) Threatened or endangered As required by the ESA (16 U.S.C.
species. 1531 et seq.).
(5) Sensitive biological resources Essential fish habitat, refuges,
or habitats. preserves, special management areas
identified in coastal management
programs, sanctuaries, rookeries,
hard bottom habitat, chemosynthetic
communities, calving grounds,
barrier islands, beaches, dunes,
and wetlands.
(6) Archaeological resources...... As required by NHPA (16 U.S.C. 470
et seq.), as amended.
(7) Social and economic conditions Employment, existing offshore and
coastal infrastructure (including
major sources of supplies,
services, energy, and water), land
use, subsistence resources and
harvest practices, recreation,
recreational and commercial fishing
(including typical fishing seasons,
location, and type), minority and
lower income groups, coastal zone
management programs, and viewshed.
(8) Coastal and marine uses....... Military activities, vessel traffic,
and energy and non-energy mineral
exploration or development.
(9) Consistency Certification..... If required by CZMA, as appropriate:
(A) 15 CFR part 930, subpart D, if
the GAP is submitted prior to lease
or grant issuance; (B) 15 CFR part
930, subpart E, if the GAP is
submitted after lease or grant
issuance.
(10) Other resources, conditions, As required by BOEM.
and activities.
------------------------------------------------------------------------

[79 FR 21625, Apr. 17, 2014]

Sec. 585.647 How will my GAP be processed for Federal consistency
under the Coastal Zone Management Act?

Your GAP will be processed based on whether it is submitted before
or after your lease or grant is issued:

------------------------------------------------------------------------
Consistency review of your GAP will
If your GAP is submitted: be handled as follows:
------------------------------------------------------------------------
(a) Before lease or grant issuance You will furnish a copy of your GAP,
consistency certification, and
necessary data and information
pursuant to 15 CFR part 930,
subpart D, to the applicable State
CZMA agency or agencies and BOEM at
the same time.
(b) After lease or grant issuance. You will submit a copy of your GAP,
consistency certification, and
necessary data and information
pursuant to 15 CFR 930, subpart E
to BOEM. BOEM will forward to the
applicable State CZMA agency or
agencies one paper copy and one
electronic copy of your GAP,
consistency certification, and
necessary data and information
required under 15 CFR part 930,
subpart E, after BOEM has
determined that all information
requirements for the GAP are met.
------------------------------------------------------------------------

[[Page 609]]

[79 FR 21625, Apr. 17, 2014]

Sec. 585.648 How will BOEM process my GAP?

(a) BOEM will review your submitted GAP, along with the information
and certifications provided pursuant to Sec. 585.646, to determine if
it contains all the required information necessary to conduct our
technical and environmental reviews.
(1) We will notify you if we deem your proposed facility or
combination of facilities to be complex or significant; and
(2) We will notify you if your submitted GAP lacks any necessary
information.
(b) BOEM will prepare appropriate NEPA analysis.
(c) When appropriate, we will coordinate and consult with relevant
State and Federal agencies and affected Indian Tribes and provide to
other local, State, and Federal agencies and affected Indian Tribes
relevant nonproprietary data and information pertaining to your proposed
activities.
(d) During the review process, we may request additional information
if we determine that the information provided is not sufficient to
complete the review and approval process. If you fail to provide the
requested information, BOEM may disapprove your GAP.
(e) Upon completion of our technical and environmental reviews and
other reviews required by Federal law (e.g., CZMA), BOEM may approve,
disapprove, or approve with modifications your GAP.
(1) If we approve your GAP, we will specify terms and conditions to
be incorporated into your GAP. You must certify compliance with certain
of those terms and conditions, as required under Sec. 585.653(c); and
(2) If we disapprove your GAP, we will inform you of the reasons and
allow you an opportunity to resubmit a revised plan making the necessary
corrections, and may suspend the term of your lease or grant, as
appropriate, to allow this to occur.

Sec. 585.649 [Reserved]

Activities Under an Approved GAP

Sec. 585.650 When may I begin conducting activities under my GAP?

After BOEM approves your GAP, you may begin conducting the approved
activities that do not involve a project easement or the construction of
facilities on the OCS that BOEM has deemed to be complex or significant.

Sec. 585.651 When may I construct complex or significant OCS facilities
on my limited lease or any facilities on my project easement
proposed under my GAP?

If you are applying for a project easement, or installing a facility
or a combination of facilities on your limited lease deemed by BOEM to
be complex or significant, as provided in Sec. 585.648(a)(1), you also
must comply with the requirements of subpart G of this part and submit
your Safety Management System description required by Sec. 585.810
before construction may begin.

Sec. 585.652 How long do I have to conduct activities under an approved GAP?

After BOEM approves your GAP, you have:
(a) For a limited lease, 5 years to conduct your approved
activities, unless we renew the term under Sec. Sec. 585.425 through
585.429.
(b) For a ROW grant or RUE grant, the time provided in the terms of
the grant.

Sec. 585.653 What other reports or notices must I submit to BOEM
under my approved GAP?

(a) You must notify BOEM in writing within 30 days after completing
installation activities approved in your GAP.
(b) You must prepare and submit to BOEM annually a report that
summarizes the findings from any activities you conduct under your
approved GAP and the results of those activities. We will protect the
information from public disclosure as provided in Sec. 585.113.
(c) You must annually (or other frequency as determined by BOEM)
submit a certification of compliance with those terms and conditions of
your

[[Page 610]]

GAP that BOEM identifies under Sec. 585.648(e)(1). Together with your
certification, you must submit:
(1) Summary reports that show compliance with the terms and
conditions which require certification; and
(2) A statement identifying and describing any mitigation measures
and monitoring methods and their effectiveness. If you identified
measures that were not effective, you must include your recommendations
for new mitigation measures or monitoring methods.

Sec. 585.654 [Reserved]

Sec. 585.655 What activities require a revision to my GAP,
and when will BOEM approve the revision?

(a) You must notify BOEM in writing before conducting any activities
not described in your approved GAP, describing in detail the type of
activities you propose to conduct. We will determine whether the
activities you propose are authorized by your existing GAP or require a
revision to your GAP. We may request additional information from you, if
necessary, to make this determination.
(b) BOEM will periodically review the activities conducted under an
approved GAP. The frequency and extent of the review will be based on
the significance of any changes in available information and on onshore
or offshore conditions affecting, or affected by, the activities
conducted under your GAP. If the review indicates that the GAP should be
revised to meet the requirement of this part, we will require you to
submit the needed revisions.
(c) Activities for which a proposed revision to your GAP will likely
be necessary include:
(1) Activities not described in your approved GAP;
(2) Modifications to the size or type of facility or equipment you
will use;
(3) Change in the surface location of a facility or structure;
(4) Addition of a facility or structure not contemplated in your
approved GAP;
(5) Change in the location of your onshore support base from one
State to another or to a new base requiring expansion;
(6) Changes in the locations of bottom disturbances (anchors,
chains, etc.) by 500 feet (152 meters) or greater from the approved
locations. If a specific anchor pattern was approved as a mitigation
measure to avoid contact with bottom features, any change in the
proposed bottom disturbances would likely trigger the need for a
revision;
(7) Structural failure of one or more facilities; or
(8) Change to any other activity specified by BOEM.
(d) We may begin the appropriate NEPA analysis and any relevant
consultations when we determine that a proposed revision could:
(1) Result in a significant change in the impacts previously
identified and evaluated;
(2) Require any additional Federal authorizations; or
(3) Involve activities not previously identified and evaluated.
(e) When you propose a revision, we may approve the revision if we
determine that the revision is:
(1) Designed not to cause undue harm or damage to natural resources;
life (including human and wildlife); property; the marine, coastal, or
human environment; or sites, structures, or objects of historical or
archaeological significance; and
(2) Otherwise consistent with the provisions of subsection 8(p) of
the OCS Lands Act.

Sec. 585.656 What must I do if I cease activities approved in my GAP
before the end of my term?

You must notify the BOEM any time you cease activities under your
approved GAP without an approved suspension. If you cease activities for
an indefinite period that exceeds 6 months, BOEM may cancel your lease
or grant under Sec. 585.437, as applicable, and you must initiate the
decommissioning process, as set forth in subpart I of this part.

Sec. 585.657 What must I do upon completion of approved activities
under my GAP?

Upon completion of your approved activities under your GAP, you must
initiate the decommissioning process as set forth in subpart I of this
part.

[[Page 611]]

You must submit your decommissioning application as provided in
Sec. Sec. 585.905 and 585.906.

Cable and Pipeline Deviations

Sec. 585.658 Can my cable or pipeline construction deviate
from my approved COP or GAP?

(a) You must make every effort to ensure that all cables and
pipelines are constructed in a manner that minimizes deviations from the
approved plan under your lease or grant.
(b) If BOEM determines that a significant change in conditions has
occurred that would necessitate an adjustment to your ROW, RUE or lease
before the commencement of construction of the cable or pipeline on the
grant or lease, BOEM will consider modifications to your ROW grant, RUE
grant, or your lease addendum for a project easement in connection with
your COP or GAP.
(c) If, after construction, it is determined that a deviation from
the approved plan has occurred, you must:
(1) Notify the operators of all leases (including mineral leases
issued under this subchapter) and holders of all ROW grants or RUE
grants (including all grants issued under this subchapter) which include
the area where a deviation has occurred and provide BOEM with evidence
of such notification;
(2) Relinquish any unused portion of your lease or grant; and
(3) Submit a revised plan for BOEM approval as necessary.
(d) Construction of a cable or pipeline that substantially deviates
from the approved plan may be grounds for cancellation of the lease or
grant.

Sec. 585.659 What requirements must I include in my SAP, COP,
or GAP regarding air quality?

(a) You must comply with the Clean Air Act (42 U.S.C. 7409) and its
implementing regulations, according to the following table.

------------------------------------------------------------------------
If your project is located . . . you must . . .
------------------------------------------------------------------------
(1) in the Gulf of Mexico west of include in your plan any
87.5[deg] west longitude (western Gulf information required for BOEM
of Mexico). to make the appropriate air
quality determinations for
your project.
(2) anywhere else on the OCS........... follow the appropriate
implementing regulations as
promulgated by the EPA under
40 CFR part 55.
------------------------------------------------------------------------

(b) For air quality modeling that you perform in support of the
activities proposed in your plan, you should contact the appropriate
regulatory agency to establish a modeling protocol to ensure that the
agency's needs are met and that the meteorological files used are
acceptable before initiating the modeling work. In the western Gulf of
Mexico (west of 87.5[deg] west longitude), you must submit to BOEM three
copies of the modeling report and three sets of digital files as
supporting information. The digital files must contain the formatted
meteorological files used in the modeling runs, the model input file,
and the model output file.

Subpart G_Facility Design, Fabrication, and Installation

Reports

Sec. 585.700 What reports must I submit to BOEM before installing facilities
described in my approved SAP, COP, or GAP?

(a) You must submit the following reports to BOEM before installing
facilities described in your approved COP (Sec. 585.632(a)) and, when
required by this part, your SAP (Sec. 585.614(b)) or GAP (Sec.
585.651):
(1) A Facility Design Report; and
(2) A Fabrication and Installation Report.
(b) You may begin to fabricate and install the approved facilities
after BOEM notifies you that it has received your reports and has no
objections. If BOEM receives the reports, but does

[[Page 612]]

not respond with objections within 60 days of receipt or 60 days after
we approve your SAP, COP, or GAP, if you submitted your report with the
plan, BOEM is deemed not to have objections to the reports, and you may
commence fabrication and installation of your facility or facilities.
(c) If BOEM has any objections, we will notify you verbally or in
writing within 60 days of receipt of the report. Following initial
notification of objections, BOEM may follow up with written
correspondence outlining its specific objections to the report and
request that certain actions be undertaken. You cannot commence
activities addressed in such report until you resolve all objections to
BOEM's satisfaction.

Sec. 585.701 What must I include in my Facility Design Report?

(a) Your Facility Design Report provides specific details of the
design of any facilities, including cables and pipelines that are
outlined in your approved SAP, COP, or GAP. Your Facility Design Report
must demonstrate that your design conforms to your responsibilities
listed in Sec. 585.105(a). You must include the following items in your
Facility Design Report:

------------------------------------------------------------------------
Required documents Required contents Other requirements
------------------------------------------------------------------------
(1) Cover letter............ (i) Proposed You must submit 1
facility paper copy and 1
designations; electronic copy.
(ii) Lease, ROW
grant or RUE grant
number;.
(iii) Area; name and
block numbers; and.
(iv) The type of
facility..
(2) Location plat........... (i) Latitude and Your plat must be
longitude drawn to a scale of
coordinates, 1 inch equals 100
Universal Mercator feet and include
grid-system the coordinates of
coordinates, state the lease, ROW
plane coordinates grant, or RUE grant
in the Lambert or block boundary
Transverse Mercator lines. You must
Projection System; submit 1 paper copy
(ii) Distances in and 1 electronic
feet from the copy.
nearest block
lines. These
coordinates must be
based on the NAD
(North American
Datum) 83 datum
plane coordinate
system; and.
(iii) The location
of any proposed
project easement..
(3) Front, Side, and Plan (i) Facility Your drawing sizes
View drawings. dimensions and must not exceed
orientation; 11 x
(ii) Elevations 17. You
relative to Mean must submit 1 paper
Lower Low Water; copy and 1
and. electronic copy.
(iii) Pile sizes and
penetration..
(4) Complete set of The approved for Your drawing sizes
structural drawings. construction must not exceed
fabrication 11 x
drawings should be 17. You
submitted must submit 1 paper
including, e.g., copy and 1
(i) Cathodic electronic copy.
protection systems;.
(ii) Jacket design;.
(iii) Pile
foundations;.
(iv) Mooring and
tethering systems;.
(v) Foundations and
anchoring systems;
and.
(vi) Associated
cable and pipeline
designs..
(5) Summary of environmental A summary of the You must submit 1
data used for design. environmental data paper copy and 1
used in the design electronic copy. If
or analysis of the you submitted these
facility. Examples data as part of
of relevant data your SAP, COP, or
include information GAP, you may
on: reference the plan.
(i) Extreme weather;
(ii) Seafloor
conditions; and.
(iii) Waves, wind,
current, tides,
temperature, snow
and ice effects,
marine growth, and
water depth..

[[Page 613]]

(6) Summary of the (i) Loading You must submit 1
engineering design data. information (e.g., paper copy and 1
live, dead, electronic copy.
environmental);
(ii) Structural
information (e.g.,
design-life;
material types;
cathodic protection
systems; design
criteria; fatigue
life; jacket
design; deck
design; production
component design;
foundation pilings
and templates, and
mooring or
tethering systems;
fabrication and
installation
guidelines); and.
(iii) Location of
foundation
boreholes and
foundation piles;
and.
(iv) Foundation
information (e.g.,
soil stability,
design criteria)..
(7) A complete set of design Self-explanatory.... You must submit 1
calculations. paper copy and 1
electronic copy.
(8) Project-specific studies All studies You must submit 1
used in the facility design pertinent to paper copy and 1
or installation. facility design or electronic copy.
installation, e.g.,
oceanographic and
soil reports
including the
results of the
surveys required in
Sec. Sec.
585.610(b),
585.627(a), or
585.645(a).
(9) Description of the loads (i) Loads imposed by You must submit 1
imposed on the facility. jacket; paper copy and 1
(ii) Decks;......... electronic copy.
(iii) Production
components;.
(iv) Foundations,
foundation pilings
and templates, and
anchoring systems;
and.
(v) Mooring or
tethering systems..
(10) Geotechnical Report.... A list of all data You must submit 1
from borings and paper copy and 1
recommended design electronic copy.
parameters.
------------------------------------------------------------------------

(b) For any floating facility, your design must meet the
requirements of the U.S. Coast Guard for structural integrity and
stability (e.g., verification of center of gravity). The design must
also consider:
(1) Foundations, foundation pilings and templates, and anchoring
systems; and
(2) Mooring or tethering systems.
(c) You must provide the location of records, as required in Sec.
585.714(c).
(d) If you are required to use a CVA, the Facility Design Report
must include one paper copy of the following certification statement:
``The design of this structure has been certified by a BOEM approved CVA
to be in accordance with accepted engineering practices and the approved
SAP, GAP, or COP as appropriate. The certified design and as-built plans
and specifications will be on file at (given location).''
(e) BOEM will withhold trade secrets and commercial or financial
information that is privileged or confidential from public disclosure
under exemption 4 of the FOIA and in accordance with the terms of Sec.
585.113.

Sec. 585.702 What must I include in my Fabrication and Installation Report?

(a) Your Fabrication and Installation Report must describe how your
facilities will be fabricated and installed in accordance with the
design criteria identified in the Facility Design Report; your approved
SAP, COP, or GAP; and generally accepted industry standards and
practices. Your Fabrication and Installation Report must demonstrate how
your facilities will be fabricated and installed in a manner that
conforms to your responsibilities listed in Sec. 585.105(a). You must
include the following items in your Fabrication and Installation Report:

[[Page 614]]

(2) Schedule................ Fabrication and You must submit 1
installation. paper copy and 1
electronic copy.
(3) Fabrication information. The industry You must submit 1
standards you will paper copy and 1
use to ensure the electronic copy.
facilities are
fabricated to the
design criteria
identified in your
Facility Design
Report.
(4) Installation process Details associated You must submit 1
information. with the deployment paper copy and 1
activities, electronic copy.
equipment, and
materials,
including onshore
and offshore
equipment and
support, and
anchoring and
mooring patterns.
(5) Federal, State, and Either 1 copy of the You must submit 1
local permits (e.g., EPA, permit or paper copy and 1
Army Corps of Engineers). information on the electronic copy.
status of the
application.
(6) Environmental (i) Water discharge; You must submit 1
information. (ii) Waste disposal; paper copy and 1
(iii) Vessel electronic copy. If
information; and. you submitted these
(iv) Onshore waste data as part of
receiving treatment your SAP, COP, or
or disposal GAP, you may
facilities.. reference the plan.
(7) Project easement........ Design of any You must submit 1
cables, pipelines, paper copy and 1
or facilities. electronic copy.
Information on
burial methods and
vessels.
------------------------------------------------------------------------

(b) You must provide the location of records, as required in Sec.
585.714(c).
(c) If you are required to use a CVA, the Fabrication and
Installation Report must include one paper copy of the following
certification statement: ``The fabrication and installation of this
structure has been certified by a BOEM approved CVA to be in accordance
with accepted engineering practices and the approved SAP, GAP, or COP as
appropriate. The certified design and as-built plans and specifications
will be on file at (given location).''
(d) BOEM will withhold trade secrets and commercial or financial
information that is privileged or confidential from public disclosure
under exemption 4 of the FOIA and in accordance with the terms of Sec.
585.113.

Sec. 585.703 What reports must I submit for project
modifications and repairs?

(a) You must verify and, in a report to us, certify that major
repairs and major modifications to the project conform to accepted
engineering practices.
(1) A major repair is a corrective action involving structural
members affecting the structural integrity of a portion of or all the
facility.
(2) A major modification is an alteration involving structural
members affecting the structural integrity of a portion of or all the
facility.
(b) The report must also identify the location of all records
pertaining to the major repairs or major modifications, as required in
Sec. 585.714(c).
(c) BOEM may require you to use a CVA for project modifications and
repairs.

Sec. 585.704 [Reserved]

Certified Verification Agent

Sec. 585.705 When must I use a Certified Verification Agent (CVA)?

You must use a CVA to review and certify the Facility Design Report,
the Fabrication and Installation Report, and the Project Modifications
and Repairs Report.
(a) You must use a CVA to:
(1) Ensure that your facilities are designed, fabricated, and
installed in conformance with accepted engineering practices and the
Facility Design Report and Fabrication and Installation Report;
(2) Ensure that repairs and major modifications are completed in
conformance with accepted engineering practices; and
(3) Provide BOEM immediate reports of all incidents that affect the
design, fabrication, and installation of the project and its components.
(b) BOEM may waive the requirement that you use a CVA if you can
demonstrate the following:

[[Page 615]]

------------------------------------------------------------------------
Then BOEM may waive the
If you demonstrate that . . . requirement for a CVA for the
following:
------------------------------------------------------------------------
(1) The facility design conforms to a The design of your
standard design that has been used structure(s).
successfully in a similar environment,
and the installation design conforms
to accepted engineering practices.
(2) The manufacturer has successfully The fabrication of your
manufactured similar facilities, and structure(s).
the facility will be fabricated in
conformance with accepted engineering
practices.
(3) The installation company has The installation of your
successfully installed similar structure(s).
facilities in a similar offshore
environment, and your structure(s)
will be installed in conformance with
accepted engineering practices.
(4) Repairs and major modifications The repair or major
will be completed in conformance with modification of your
accepted engineering practices. structure(s).
------------------------------------------------------------------------

(c) You must submit a request to waive the requirement to use a CVA
to BOEM in writing, along with your SAP under Sec. 585.610(a)(9), COP
under Sec. 585.626(b)(20), or GAP under Sec. 585.645(c)(5).
(1) BOEM will review your request to waive the use of the CVA and
notify you of our decision along with our decision on your SAP, COP, or
GAP.
(2) If BOEM does not waive the requirement for a CVA, you may file
an appeal under Sec. 585.118.
(3) If BOEM waives the requirement that you use a CVA, your project
engineer must perform the same duties and responsibilities as the CVA,
except as otherwise provided.

Sec. 585.706 How do I nominate a CVA for BOEM approval?

(a) As part of your COP (as provided in Sec. 585.626(b)(20) and,
when required by this part, your SAP (Sec. 585.610(a)(9)) or GAP (Sec.
585.645(c)(5)), you must nominate a CVA for BOEM approval. You must
specify whether the nomination is for the Facility Design Report,
Fabrication and Installation Report, Modification and Repair Report, or
for any combination of these.
(b) For each CVA that you nominate, you must submit to BOEM a list
of documents used in your design that you will forward to the CVA and a
qualification statement that includes the following:
(1) Previous experience in third-party verification or experience in
the design, fabrication, installation, or major modification of offshore
energy facilities;
(2) Technical capabilities of the individual or the primary staff
for the specific project;
(3) Size and type of organization or corporation;
(4) In-house availability of, or access to, appropriate technology
(including computer programs, hardware, and testing materials and
equipment);
(5) Ability to perform the CVA functions for the specific project
considering current commitments;
(6) Previous experience with BOEM requirements and procedures, if
any; and
(7) The level of work to be performed by the CVA.
(c) Individuals or organizations acting as CVAs must not function in
any capacity that will create a conflict of interest, or the appearance
of a conflict of interest.
(d) The verification must be conducted by or under the direct
supervision of registered professional engineers.
(e) BOEM will approve or disapprove your CVA as part of its review
of the COP or, when required, of your SAP or GAP.
(f) You must nominate a new CVA for BOEM approval if the previously
approved CVA:
(1) Is no longer able to serve in a CVA capacity for the project; or
(2) No longer meets the requirements for a CVA set forth in this
subpart.

Sec. 585.707 What are the CVA's primary duties for facility design review?

If you are required to use a CVA:
(a) The CVA must use good engineering judgment and practices in
conducting an independent assessment of the design of the facility. The
CVA must certify in the Facility Design Report to BOEM that the facility
is designed to withstand the environmental

[[Page 616]]

and functional load conditions appropriate for the intended service life
at the proposed location.
(b) The CVA must conduct an independent assessment of all proposed:
(1) Planning criteria;
(2) Operational requirements;
(3) Environmental loading data;
(4) Load determinations;
(5) Stress analyses;
(6) Material designations;
(7) Soil and foundation conditions;
(8) Safety factors; and
(9) Other pertinent parameters of the proposed design.
(c) For any floating facility, the CVA must ensure that any
requirements of the U.S. Coast Guard for structural integrity and
stability (e.g., verification of center of gravity), have been met. The
CVA must also consider:
(1) Foundations, foundation pilings and templates, and anchoring
systems; and
(2) Mooring or tethering systems.

Sec. 585.708 What are the CVA's or project engineer's primary duties
for fabrication and installation review?

(a) The CVA or project engineer must do all of the following:
(1) Use good engineering judgment and practice in conducting an
independent assessment of the fabrication and installation activities;
(2) Monitor the fabrication and installation of the facility as
required by paragraph (b) of this section;
(3) Make periodic onsite inspections while fabrication is in
progress and verify the items required by Sec. 585.709;
(4) Make periodic onsite inspections while installation is in
progress and satisfy the requirements of Sec. 585.710; and
(5) Certify in a report that project components are fabricated and
installed in accordance with accepted engineering practices; your
approved COP, SAP, or GAP (as applicable); and the Fabrication and
Installation Report.
(i) The report must also identify the location of all records
pertaining to fabrication and installation, as required in Sec.
585.714(c); and
(ii) You may commence commercial operations or other approved
activities 30 days after BOEM receives that certification report, unless
BOEM notifies you within that time period of its objections to the
certification report.
(b) To comply with paragraph (a)(5) of this section, the CVA or
project engineer must monitor the fabrication and installation of the
facility to ensure that it has been built and installed according to the
Facility Design Report and Fabrication and Installation Report.
(1) If the CVA or project engineer finds that fabrication and
installation procedures have been changed or design specifications have
been modified, the CVA or project engineer must inform you; and
(2) If you accept the modifications, then you must also inform BOEM.

Sec. 585.709 When conducting onsite fabrication inspections,
what must the CVA or project engineer verify?

(a) To comply with Sec. 585.708(a)(3), the CVA or project engineer
must make periodic onsite inspections while fabrication is in progress
and must verify the following fabrication items, as appropriate:
(1) Quality control by lessee (or grant holder) and builder;
(2) Fabrication site facilities;
(3) Material quality and identification methods;
(4) Fabrication procedures specified in the Fabrication and
Installation Report, and adherence to such procedures;
(5) Welder and welding procedure qualification and identification;
(6) Structural tolerances specified, and adherence to those
tolerances;
(7) Nondestructive examination requirements and evaluation results
of the specified examinations;
(8) Destructive testing requirements and results;
(9) Repair procedures;
(10) Installation of corrosion-protection systems and splash-zone
protection;
(11) Erection procedures to ensure that overstressing of structural
members does not occur;
(12) Alignment procedures;
(13) Dimensional check of the overall structure, including any
turrets, turret-and-hull interfaces, any mooring line and chain and
riser tensioning line segments; and

[[Page 617]]

(14) Status of quality-control records at various stages of
fabrication.
(b) For any floating facilities, the CVA or project engineer must
ensure that any requirements of the U.S. Coast Guard for structural
integrity and stability (e.g., verification of center of gravity) have
been met. The CVA or project engineer must also consider:
(1) Foundations, foundation pilings and templates, and anchoring
systems; and
(2) Mooring or tethering systems.

Sec. 585.710 When conducting onsite installation inspections,
what must the CVA or project engineer do?

To comply with Sec. 585.708(a)(4), the CVA or project engineer must
make periodic onsite inspections while installation is in progress and
must, as appropriate, verify, witness, survey, or check, the
installation items required by this section.
(a) The CVA or project engineer must verify, as appropriate, all of
the following:
(1) Loadout and initial flotation procedures;
(2) Towing operation procedures to the specified location, and
review the towing records;
(3) Launching and uprighting activities;
(4) Submergence activities;
(5) Pile or anchor installations;
(6) Installation of mooring and tethering systems;
(7) Final deck and component installations; and
(8) Installation at the approved location according to the Facility
Design Report and the Fabrication and Installation Report.
(b) For a fixed or floating facility, the CVA or project engineer
must verify that proper procedures were used during the following:
(1) The loadout of the jacket, decks, piles, or structures from each
fabrication site; and
(2) The actual installation of the facility or major modification
and the related installation activities.
(c) For a floating facility, the CVA or project engineer must verify
that proper procedures were used during the following:
(1) The loadout of the facility;
(2) The installation of foundation pilings and templates, and
anchoring systems; and
(3) The installation of the mooring and tethering systems.
(d) The CVA or project engineer must conduct an onsite survey of the
facility after transportation to the approved location.
(e) The CVA or project engineer must spot-check the equipment,
procedures, and recordkeeping as necessary to determine compliance with
the applicable documents incorporated by reference and the regulations
under this part.

Sec. 585.711 [Reserved]

Sec. 585.712 What are the CVA's or project engineer's reporting requirements?

(a) The CVA or project engineer must prepare and submit to you and
BOEM all reports required by this subpart. The CVA or project engineer
must also submit interim reports to you and BOEM, as requested by the
BOEM.
(b) For each report required by this subpart, the CVA or project
engineer must submit one electronic copy and one paper copy of each
final report to BOEM. In each report, the CVA or project engineer must:
(1) Give details of how, by whom, and when the CVA or project
engineer activities were conducted;
(2) Describe the CVA's or project engineer's activities during the
verification process;
(3) Summarize the CVA's or project engineer's findings; and
(4) Provide any additional comments that the CVA or project engineer
deems necessary.

Sec. 585.713 What must I do after the CVA or project engineer confirms
conformance with the Fabrication and Installation Report
on my commercial lease?

After the CVA or project engineer files the certification report,
you must notify BOEM within 10 business days after commencing commercial
operations.

Sec. 585.714 What records relating to SAPs, COPs, and GAPs must I keep?

(a) Until BOEM releases your financial assurance under Sec.
585.534, you must

[[Page 618]]

compile, retain, and make available to BOEM representatives, within the
time specified by BOEM, all of the following:
(1) The as-built drawings;
(2) The design assumptions and analyses;
(3) A summary of the fabrication and installation examination
records;
(4) The inspection results from the inspections and assessments
required by Sec. Sec. 585.820 through 585.825; and
(5) Records of repairs not covered in the inspection report
submitted under Sec. 585.824(b)(3).
(b) You must record and retain the original material test results of
all primary structural materials during all stages of construction until
BOEM releases your financial assurance under Sec. 585.534. Primary
material is material that, should it fail, would lead to a significant
reduction in facility safety, structural reliability, or operating
capabilities. Items such as steel brackets, deck stiffeners and
secondary braces or beams would not generally be considered primary
structural members (or materials).
(c) You must provide BOEM with the location of these records in the
certification statement, as required in Sec. Sec. 585.701(c),
585.703(b), and 585.708(a)(5)(i).

Subpart H_Environmental and Safety Management, Inspections, and Facility
Assessments for Activities Conducted Under SAPs, COPs and GAPs

Sec. 585.800 How must I conduct my activities to comply with safety
and environmental requirements?

(a) You must conduct all activities on your lease or grant under
this part in a manner that conforms with your responsibilities in Sec.
585.105(a), and using:
(1) Trained personnel; and
(2) Technologies, precautions, and techniques that will not cause
undue harm or damage to natural resources, including their physical,
atmospheric, and biological components.
(b) You must certify compliance with those terms and conditions
identified in your approved SAP, COP, or GAP, as required under Sec.
585.615(c), Sec. 585.633(b), or Sec. 585.653(c).

Sec. 585.801 How must I conduct my approved activities
to protect marine mammals, threatened and endangered species,
and designated critical habitat?

(a) You must not conduct any activity under your lease or grant that
may affect threatened or endangered species or that may affect
designated critical habitat of such species until the appropriate level
of consultation is conducted, as required under the ESA, as amended (16
U.S.C. 1531 et seq.), to ensure that your actions are not likely to
jeopardize a threatened or endangered species and are not likely to
destroy or adversely modify designated critical habitat.
(b) You must not conduct any activity under your lease or grant that
may result in an incidental taking of marine mammals until the
appropriate authorization has been issued under the Marine Mammal
Protection Act of 1972 (MMPA) as amended (16 U.S.C. 1361 et seq.).
(c) If there is reason to believe that a threatened or endangered
species may be present while you conduct your BOEM approved activities
or may be affected by the direct or indirect effects of your actions:
(1) You must notify us that endangered or threatened species may be
present in the vicinity of the lease or grant or may be affected by your
actions; and
(2) We will consult with appropriate State and Federal fish and
wildlife agencies and, after consultation, shall identify whether, and
under what conditions, you may proceed.
(d) If there is reason to believe that designated critical habitat
of a threatened or endangered species may be affected by the direct or
indirect effects of your BOEM approved activities:
(1) You must notify us that designated critical habitat of a
threatened or endangered species in the vicinity of the lease or grant
may be affected by your actions; and
(2) We will consult with appropriate State and Federal fish and
wildlife agencies and, after consultation, shall identify whether, and
under what conditions, you may proceed.

[[Page 619]]

(e) If there is reason to believe that marine mammals may be
incidentally taken as a result of your proposed activities:
(1) You must agree to secure an authorization from National Oceanic
and Atmospheric Administration (NOAA) or the U.S. Fish and Wildlife
Service (FWS) for incidental taking, including taking by harassment,
that may result from your actions; and
(2) You must comply with all measures required by the NOAA or FWS,
including measures to affect the least practicable impact on such
species and its habitat and to ensure no immitigable adverse impact on
the availability of the species for subsistence use.
(f) Submit to us:
(1) Measures designed to avoid or minimize adverse effects and any
potential incidental take of the endangered or threatened species or
marine mammals;
(2) Measures designed to avoid likely adverse modification or
destruction of designated critical habitat of such endangered or
threatened species; and
(3) Your agreement to monitor for the incidental take of the species
and adverse effects on the critical habitat, and provide the results of
the monitoring to BOEM as required; and
(4) Your agreement to perform any relevant terms and conditions of
the Incidental Take Statement that may result from the ESA consultation.
(5) Your agreement to perform any relevant mitigation measures under
an MMPA incidental take authorization.

Sec. 585.802 What must I do if I discover a potential
archaeological resource while conducting my approved activities?

(a) If you, your subcontractors, or any agent acting on your behalf
discovers a potential archaeological resource while conducting
construction activities, or any other activity related to your project,
you must:
(1) Immediately halt all seafloor-disturbing activities within the
area of the discovery;
(2) Notify BOEM of the discovery within 72 hours; and
(3) Keep the location of the discovery confidential and not take any
action that may adversely affect the archaeological resource until we
have made an evaluation and instructed you on how to proceed.
(b) We may require you to conduct additional investigations to
determine if the resource is eligible for listing in the National
Register of Historic Places under 36 CFR 60.4. We will do this if:
(1) The site has been impacted by your project activities; or
(2) Impacts to the site or to the area of potential effect cannot be
avoided.
(c) If investigations under paragraph (b) of this section indicate
that the resource is potentially eligible for listing in the National
Register of Historic Places, we will tell you how to protect the
resource, or how to mitigate adverse effects to the site.
(d) If we incur costs in protecting the resource, under section
110(g) of the NHPA, we may charge you reasonable costs for carrying out
preservation responsibilities under the OCS Lands Act.

Sec. 585.803 How must I conduct my approved activities to protect
essential fish habitats identified and described under the Magnuson-Stevens
Fishery Conservation and Management Act?

(a) If, during the conduct of your approved activities, BOEM finds
that essential fish habitat or habitat areas of particular concern may
be adversely affected by your activities, BOEM must consult with
National Marine Fisheries Service.
(b) Any conservation recommendations adopted by BOEM to avoid or
minimize adverse affects on Essential Fish Habitat will be incorporated
as terms and conditions in the lease and must be adhered to by the
applicant. BOEM may require additional surveys to define boundaries and
avoidance distances.
(c) If required, BOEM will specify the survey methods and
instrumentations for conducting the biological survey and will specify
the contents of the biological report.

[[Page 620]]

Sec. Sec. 585.804-585.809 [Reserved]

Safety Management Systems

Sec. 585.810 What must I include in my Safety Management System?

You must submit a description of the Safety Management System you
will use with your COP (provided under Sec. 585.627(d)) and, when
required by this part, your SAP (as provided in Sec. 585.614(b)) or GAP
(as provided in Sec. 585.651). You must describe:
(a) How you will ensure the safety of personnel or anyone on or near
your facilities;
(b) Remote monitoring, control, and shut down capabilities;
(c) Emergency response procedures;
(d) Fire suppression equipment, if needed;
(e) How and when you will test your Safety Management System; and
(f) How you will ensure personnel who operate your facilities are
properly trained.

Sec. 585.811 When must I follow my Safety Management System?

Your Safety Management System must be fully functional when you
begin activities described in your approved COP, SAP, or GAP. You must
conduct all activities described in your approved COP, SAP, or GAP in
accordance with the Safety Management System you described, as required
by Sec. 585.810.

Sec. 585.812 [Reserved]

Maintenance and Shutdowns

Sec. 585.813 When do I have to report removing equipment from service?

(a) The removal of any equipment from service may result in BOEM
applying remedies, as provided in this part, when such equipment is
necessary for implementing your approved plan. Such remedies may include
an order from BOEM requiring you to replace or remove such equipment or
facilities.
(b)(1) You must report within 24 hours when equipment necessary for
implementing your approved plan is removed from service for more than 12
hours. If you provide an oral notification, you must submit a written
confirmation of this notice within 3 business days, as required by Sec.
585.105(c);
(2) You do not have to report removing equipment necessary for
implementing your plan if the removal is part of planned maintenance or
repair activities; and
(3) You must notify BOEM when you return the equipment to service.

Sec. 585.814 [Reserved]

Equipment Failure and Adverse Environmental Effects

Sec. 585.815 What must I do if I have facility damage
or an equipment failure?

(a) If you have facility damage or the failure of a pipeline, cable,
or other equipment necessary for you to implement your approved plan,
you must make repairs as soon as practicable. If you have a major
repair, you must submit a report of the repairs to BOEM, as required in
Sec. 585.711.
(b) If you are required to report any facility damage or failure
under Sec. 585.831, BOEM may require you to revise your SAP, COP, or
GAP to describe how you will address the facility damage or failure as
required by Sec. 585.634 (COP), Sec. 585.617 (SAP), Sec. 585.655
(GAP). You must submit a report of the repairs to BOEM, as required in
Sec. 585.703.
(c) BOEM may require that you analyze cable, pipeline, or facility
damage or failure to determine the cause. If requested by BOEM, you must
submit a comprehensive written report of the failure or damage to BOEM
as soon as available.

Sec. 585.816 What must I do if environmental or other conditions
adversely affect a cable, pipeline, or facility?

If environmental or other conditions adversely affect a cable,
pipeline, or facility so as to endanger the safety or the environment,
you must:
(a) Submit a plan of corrective action to BOEM within 30 days of the
discovery of the adverse effect.
(b) Take remedial action as described in your corrective action
plan.
(c) Submit to the BOEM a report of the remedial action taken within
30 days after completion.

[[Page 621]]

Sec. Sec. 585.817-585.819 [Reserved]

Inspections and Assessment

Sec. 585.820 Will BOEM conduct inspections?

BOEM will inspect OCS facilities and any vessels engaged in
activities authorized under this part. We conduct these inspections:
(a) To verify that you are conducting activities in compliance with
subsection 8(p) of the OCS Lands Act; the regulations in this part; the
terms, conditions, and stipulations of your lease or grant; approved
plans; and other applicable laws and regulations.
(b) To determine whether proper safety equipment has been installed
and is operating properly according to your Safety Management System, as
required in Sec. 585.810.

Sec. 585.821 Will BOEM conduct scheduled and unscheduled inspections?

BOEM will conduct both scheduled and unscheduled inspections.

Sec. 585.822 What must I do when BOEM conducts an inspection?

(a) When BOEM conducts an inspection, you must:
(1) Provide access to all facilities on your lease (including your
project easement) or grant; and
(2) Make the following available for BOEM to inspect:
(i) The area covered under a lease, ROW grant, or RUE grant;
(ii) All improvements, structures, and fixtures on these areas; and
(iii) All records of design, construction, operation, maintenance,
repairs, or investigations on or related to the area.
(b) You must retain these records in paragraph (a)(2)(iii) of this
section until BOEM releases your financial assurance under Sec. 585.534
and provide them to BOEM upon request, within the time period specified
by BOEM.
(c) You must demonstrate to the inspector how you are in compliance
with your Safety Management System.

Sec. 585.823 Will BOEM reimburse me for my expenses related to inspections?

Upon request, BOEM will reimburse you for food, quarters, and
transportation that you provide for our representatives while they
inspect your lease or grant facilities and associated activities. You
must send us your reimbursement request within 90 days of the
inspection.

Sec. 585.824 How must I conduct self-inspections?

(a) You must develop a comprehensive annual self-inspection plan
covering all of your facilities. You must keep this plan wherever you
keep your records and make it available to BOEM inspectors upon request.
Your plan must specify:
(1) The type, extent, and frequency of in-place inspections that you
will conduct for both the above-water and the below-water structures of
all facilities and pertinent components of the mooring systems for any
floating facilities; and
(2) How you are monitoring the corrosion protection for both the
above-water and below-water structures.
(b) You must submit a report annually to us no later than November 1
that must include:
(1) A list of facilities inspected in the preceding 12 months;
(2) The type of inspection employed, (i.e., visual, magnetic
particle, ultrasonic testing); and
(3) A summary of the inspection indicating what repairs, if any,
were needed and the overall structural condition of the facility.

Sec. 585.825 When must I assess my facilities?

(a) You must perform an assessment of the structure, when needed,
based on the platform assessment initiators listed in sections 17.2.1-
17.2.5 of API RP 2A-WSD, Recommended Practice for Planning, Designing
and Constructing Fixed Offshore Platforms--Working Stress Design (as
incorporated by reference in Sec. 585.115).
(b) You must initiate mitigation actions for structures that do not
pass the assessment process of API RP 2A-WSD.
(c) You must perform other assessments as required by BOEM.

[[Page 622]]

Sec. Sec. 585.826-585.829 [Reserved]

Incident Reporting and Investigation

Sec. 585.830 What are my incident reporting requirements?

(a) You must report all incidents listed in Sec. 585.831 to BOEM,
according to the reporting requirements for these incidents in
Sec. Sec. 585.832 and 585.833.
(b) These reporting requirements apply to incidents that occur on
the area covered by your lease or grant under this part and that are
related to activities resulting from the exercise of your rights under
your lease or grant under this part.
(c) Nothing in this subpart relieves you from providing notices and
reports of incidents that may be required by other regulatory agencies.
(d) You must report all spills of oil or other liquid pollutants in
accordance with 30 CFR 254.46.

Sec. 585.831 What incidents must I report, and when must I report them?

(a) You must report the following incidents to us immediately via
oral communication, and provide a written follow-up report (paper copy
or electronically transmitted) within 15 business days after the
incident:
(1) Fatalities;
(2) Incidents that require the evacuation of person(s) from the
facility to shore or to another offshore facility;
(3) Fires and explosions;
(4) Collisions that result in property or equipment damage greater
than $25,000 (Collision means the act of a moving vessel (including an
aircraft) striking another vessel, or striking a stationary vessel or
object. Property or equipment damage means the cost of labor and
material to restore all affected items to their condition before the
damage, including, but not limited to, the OCS facility, a vessel, a
helicopter, or the equipment. It does not include the cost of salvage,
cleaning, dry docking, or demurrage);
(5) Incidents involving structural damage to an OCS facility that is
severe enough so that activities on the facility cannot continue until
repairs are made;
(6) Incidents involving crane or personnel/material handling
activities, if they result in a fatality, injury, structural damage, or
significant environmental damage;
(7) Incidents that damage or disable safety systems or equipment
(including firefighting systems);
(8) Other incidents resulting in property or equipment damage
greater than $25,000; and
(9) Any other incidents involving significant environmental damage,
or harm.
(b) You must provide a written report of the following incidents to
us within 15 days after the incident:
(1) Any injuries that result in the injured person not being able to
return to work or to all of their normal duties the day after the injury
occurred; and
(2) All incidents that require personnel on the facility to muster
for evacuation for reasons not related to weather or drills.

Sec. 585.832 How do I report incidents requiring immediate notification?

For an incident requiring immediate notification under Sec.
585.831(a), you must notify BOEM verbally after aiding the injured and
stabilizing the situation. Your verbal communication must provide the
following information:
(a) Date and time of occurrence;
(b) Identification and contact information for the lessee, grant
holder, or operator;
(c) Contractor, and contractor representative's name and telephone
number (if a contractor is involved in the incident or injury/fatality);
(d) Lease number, OCS area, and block;
(e) Platform/facility name and number, or cable or pipeline segment
number;
(f) Type of incident or injury/fatality;
(g) Activity at time of incident; and
(h) Description of the incident, damage, or injury/fatality.

Sec. 585.833 What are the reporting requirements for incidents
requiring written notification?

(a) For any incident covered under Sec. 585.831, you must submit a
written report within 15 days after the incident to BOEM. The report
must contain the following information:
(1) Date and time of occurrence;

[[Page 623]]

(2) Identification and contact information for each lessee, grant
holder, or operator;
(3) Name and telephone number of the contractor and the contractor's
representative, if a contractor is involved in the incident or injury;
(4) Lease number, OCS area, and block;
(5) Platform/facility name and number, or cable or pipeline segment
number;
(6) Type of incident or injury;
(7) Activity at time of incident;
(8) Description of incident, damage, or injury (including days away
from work, restricted work, or job transfer), and any corrective action
taken; and
(9) Property or equipment damage estimate (in U.S. dollars).
(b) You may submit a report or form prepared for another agency in
lieu of the written report required by paragraph (a) of this section if
the report or form contains all required information.
(c) BOEM may require you to submit additional information about an
incident on a case-by-case basis.

Subpart I_Decommissioning

Decommissioning Obligations and Requirements

Sec. 585.900 Who must meet the decommissioning obligations in this subpart?

(a) Lessees are jointly and severally responsible for meeting
decommissioning obligations for facilities on their leases, including
all obstructions, as the obligations accrue and until each obligation is
met.
(b) Grant holders are jointly and severally liable for meeting
decommissioning obligations for facilities on their grant, including all
obstructions, as the obligations accrue and until each obligation is
met.

Sec. 585.901 When do I accrue decommissioning obligations?

You accrue decommissioning obligations when you are or become a
lessee or grant holder, and you either install, construct, or acquire by
a BOEM-approved assignment a facility, cable, or pipeline, or you create
an obstruction to other uses of the OCS.

Sec. 585.902 What are the general requirements for decommissioning
for facilities authorized under my SAP, COP, or GAP?

(a) Except as otherwise authorized by BOEM under Sec. 585.909,
within 2 years following termination of a lease or grant, you must:
(1) Remove or decommission all facilities, projects, cables,
pipelines, and obstructions;
(2) Clear the seafloor of all obstructions created by activities on
your lease, including your project easement, or grant, as required by
the BOEM.
(b) Before decommissioning the facilities under your SAP, COP, or
GAP, you must submit a decommissioning application and receive approval
from the BOEM.
(c) The approval of the decommissioning concept in the SAP, COP, or
GAP is not an approval of a decommissioning application. However, you
may submit your complete decommissioning application simultaneously with
the SAP, COP, or GAP so that it may undergo appropriate technical and
regulatory reviews at that time.
(d) Following approval of your decommissioning application, you must
submit a decommissioning notice under Sec. 585.908 to BOEM at least 60
days before commencing decommissioning activities.
(e) If you, your subcontractors, or any agent acting on your behalf
discover any archaeological resource while conducting decommissioning
activities, you must immediately halt bottom-disturbing activities
within 1,000 feet of the discovery and report the discovery to us within
72 hours. We will inform you how to conduct investigations to determine
if the resource is significant and how to protect it. You, your
subcontractors, or any agent acting on your behalf must keep the
location of the discovery confidential and must not take any action that
may adversely affect the archaeological resource until we have made an
evaluation and told you how to proceed.
(f) Provide BOEM with documentation of any coordination efforts you
have made with the affected States, local, and Tribal governments.

[[Page 624]]

Sec. 585.903 What are the requirements for decommissioning FERC-licensed
hydrokinetic facilities?

You must comply with the decommissioning requirements in your BOEM-
issued lease. If you fail to comply with the decommissioning
requirements of your lease then:
(a) BOEM may call for the forfeiture of your bond or other financial
assurance;
(b) You remain liable for removal or disposal costs and responsible
for accidents or damages that might result from such failure; and
(c) BOEM may take enforcement action under Sec. 585.400 of this
part.

Sec. 585.904 Can I request a departure from the decommissioning requirements?

You may request a departure from the decommissioning requirements
under Sec. 585.103.

Decommissioning Applications

Sec. 585.905 When must I submit my decommissioning application?

You must submit your decommissioning application upon the earliest
of the following dates:
(a) 2 years before the expiration of your lease.
(b) 90 days after completion of your commercial activities on a
commercial lease.
(c) 90 days after completion of your approved activities under a
limited lease on a ROW grant or RUE grant.
(d) 90 days after cancellation, relinquishment, or other termination
of your lease or grant.

Sec. 585.906 What must my decommissioning application include?

You must provide one paper copy and one electronic copy of the
application. Include the following information in the application, as
applicable.
(a) Identification of the applicant including:
(1) Lease operator, ROW grant holder, or RUE grant holder;
(2) Address;
(3) Contact person and telephone number; and
(4) Shore base.
(b) Identification and description of the facilities, cables, or
pipelines you plan to remove or propose to leave in place, as provided
in Sec. 585.909.
(c) A proposed decommissioning schedule for your lease, ROW grant,
or RUE grant, including the expiration or relinquishment date and
proposed month and year of removal.
(d) A description of the removal methods and procedures, including
the types of equipment, vessels, and moorings (i.e., anchors, chains,
lines, etc.) you will use.
(e) A description of your site clearance activities.
(f) Your plans for transportation and disposal (including as an
artificial reef) or salvage of the removed facilities, cables, or
pipelines and any required approvals.
(g) A description of those resources, conditions, and activities
that could be affected by or could affect your proposed decommissioning
activities. The description must be as detailed as necessary to assist
BOEM in complying with the NEPA and other relevant Federal laws.
(h) The results of any recent biological surveys conducted in the
vicinity of the structure and recent observations of turtles or marine
mammals at the structure site.
(i) Mitigation measures you will use to protect archaeological and
sensitive biological features during removal activities.
(j) A description of measures you will take to prevent unauthorized
discharge of pollutants, including marine trash and debris, into the
offshore waters.
(k) A statement of whether or not you will use divers to survey the
area after removal to determine any effects on marine life.

Sec. 585.907 How will BOEM process my decommissioning application?

(a) Based upon your inclusion of all the information required by
Sec. 585.906, BOEM will compare your decommissioning application with
the decommissioning general concept in your approved SAP, COP, or GAP to
determine what technical and environmental reviews are needed.
(b) You will likely have to revise your SAP, COP, or GAP, and BOEM

[[Page 625]]

will begin the appropriate NEPA analysis and other regulatory reviews as
required, if BOEM determines that your decommissioning application
would:
(1) Result in a significant change in the impacts previously
identified and evaluated in your SAP, COP, or GAP;
(2) Require any additional Federal permits; or
(3) Propose activities not previously identified and evaluated in
your SAP, COP, or GAP.
(c) During the review process, we may request additional information
if we determine that the information provided is not sufficient to
complete the review and approval process.
(d) Upon completion of the technical and environmental reviews, we
may approve, approve with conditions, or disapprove your decommissioning
application.
(e) If BOEM disapproves your decommissioning application, you must
resubmit your application to address the concerns identified by BOEM.

Sec. 585.908 What must I include in my decommissioning notice?

(a) The decommissioning notice is distinct from your decommissioning
application and may only be submitted following approval of your
decommissioning application, as described in Sec. Sec. 585.905 through
585.907. You must submit a decommissioning notice at least 60 days
before you plan to begin decommissioning activities.
(b) Your decommissioning notice must include:
(1) A description of any changes to the approved removal methods and
procedures in your approved decommissioning application, including
changes to the types of vessels and equipment you will use; and
(2) An updated decommissioning schedule.
(c) We will review your decommissioning notice and may require you
to resubmit a decommissioning application if BOEM determines that your
decommissioning activities would:
(1) Result in a significant change in the impacts previously
identified and evaluated;
(2) Require any additional Federal permits; or
(3) Propose activities not previously identified and evaluated.

Facility Removal

Sec. 585.909 When may BOEM authorize facilities to remain in place
following termination of a lease or grant?

(a) In your decommissioning application, you may request that
certain facilities authorized in your lease or grant remain in place for
other activities authorized in this part, elsewhere in this subchapter,
or by other applicable Federal laws.
(b) BOEM may approve such requests on a case-by-case basis
considering the following:
(1) Potential impacts to the marine environment;
(2) Competing uses of the OCS;
(3) Impacts on marine safety and National defense;
(4) Maintenance of adequate financial assurance; and
(5) Other factors determined by the Director.
(c) Except as provided in paragraph (d) of this section, if BOEM
authorizes facilities to remain in place, the former lessee or grantee
under this part remains jointly and severally liable for decommissioning
the facility unless satisfactory evidence is provided to BOEM showing
that another party has assumed that responsibility and has secured
adequate financial assurances.
(d) In your decommissioning application, you may request that
certain facilities authorized in your lease or grant be converted to an
artificial reef or otherwise toppled in place. BOEM will evaluate all
such requests.

Sec. 585.910 What must I do when I remove my facility?

(a) You must remove all facilities to a depth of 15 feet below the
mudline, unless otherwise authorized by BOEM.
(b) Within 60 days after you remove a facility, you must verify to
BOEM that you have cleared the site.

[[Page 626]]

Sec. 585.911 [Reserved]

Decommissioning Report

Sec. 585.912 After I remove a facility, cable, or pipeline,
what information must I submit?

Within 60 days after you remove a facility, cable, or pipeline, you
must submit a written report to BOEM that includes the following:
(a) A summary of the removal activities, including the date they
were completed;
(b) A description of any mitigation measures you took; and
(c) If you used explosives, a statement signed by your authorized
representative that certifies that the types and amount of explosives
you used in removing the facility were consistent with those in the
approved decommissioning application.

Compliance With an Approved Decommissioning Application

Sec. 585.913 What happens if I fail to comply with my approved
decommissioning application?

If you fail to comply with your approved decommissioning plan or
application:
(a) BOEM may call for the forfeiture of your bond or other financial
assurance;
(b) You remain liable for removal or disposal costs and responsible
for accidents or damages that might result from such failure; and
(c) BOEM may take enforcement action under Sec. 585.400.

Subpart J_Rights of Use and Easement for Energy- and Marine-Related
Activities Using Existing OCS Facilities

Regulated Activities

Sec. 585.1000 What activities does this subpart regulate?

(a) This subpart provides the general provisions for authorizing and
regulating activities that use (or propose to use) an existing OCS
facility for energy- or marine-related purposes, that are not otherwise
authorized under any other part of this subchapter or any other
applicable Federal statute. Activities authorized under any other part
of this subchapter or under any other Federal law that use (or propose
to use) an existing OCS facility are not subject to this subpart.
(b) BOEM will issue an Alternate Use RUE for activities authorized
under this subpart.
(c) At the discretion of the Director, an Alternate Use RUE may:
(1) Permit alternate use activities to occur at an existing facility
that is currently in use under an approved OCS lease; or
(2) Limit alternate use activities at the existing facility until
after previously authorized activities at the facility have ceased and
the OCS lease terminates.

Sec. Sec. 585.1001-585.1003 [Reserved]

Requesting an Alternate Use RUE

Sec. 585.1004 What must I do before I request an Alternate Use RUE?

If you are not the owner of the existing facility on the OCS and the
lessee of the area in which the facility is located, you must contact
the lessee and owner of the facility and reach a preliminary agreement
as to the proposed activity for the use of the existing facility.

Sec. 585.1005 How do I request an Alternate Use RUE?

To request an Alternate Use RUE, you must submit to BOEM all of the
following:
(a) The name, address, e-mail address, and phone number of an
authorized representative.
(b) A summary of the proposed activities for the use of an existing
OCS facility, including:
(1) The type of activities that would involve the use of the
existing OCS facility;
(2) A description of the existing OCS facility, including a map
providing its location on the lease block;
(3) The names of the owner of the existing OCS facility, the
operator, the lessee, and any owner of operating rights on the lease at
which the facility is located;

[[Page 627]]

(4) A description of additional structures or equipment that will be
required to be located on or in the vicinity of the existing OCS
facility in connection with the proposed activities;
(5) A statement indicating whether any of the proposed activities
are intended to occur before existing activities on the OCS facility
have ceased; and
(6) A statement describing how existing activities at the OCS
facility will be affected if proposed activities are to occur at the
same time as existing activities at the OCS facility.
(c) A statement affirming that the proposed activities sought to be
approved under this subpart are not otherwise authorized by other
provisions in this subchapter or any other Federal law.
(d) Evidence that you meet the requirements of Sec. 585.106, as
required by Sec. 585.107.
(e) The signatures of the applicant, the owner of the existing OCS
facility, and the lessee of the area in which the existing facility is
located.

Sec. 585.1006 How will BOEM decide whether to issue an Alternate Use RUE?

(a) We will consider requests for an Alternate Use RUE on a case-by-
case basis. In considering such requests, we will consult with relevant
Federal agencies and evaluate whether the proposed activities involving
the use of an existing OCS facility can be conducted in a manner that:
(1) Ensures safety and minimizes adverse effects to the coastal and
marine environments, including their physical, atmospheric, and
biological components, to the extent practicable;
(2) Does not inhibit or restrain orderly development of OCS mineral
or energy resources; and
(3) Avoids serious harm or damage to, or waste of, any natural
resource (including OCS mineral deposits and oil, gas, and sulphur
resources in areas leased or not leased), any life (including fish and
other aquatic life), or property (including sites, structures, or
objects of historical or archaeological significance);
(4) Is otherwise consistent with subsection 8(p) of the OCS Lands
Act; and
(5) BOEM can effectively regulate.
(b) Based on the evaluation that we perform under paragraph (a) of
this section, the BOEM may authorize or reject, or authorize with
modifications or stipulations, the proposed activity.

Sec. 585.1007 What process will BOEM use for competitively
offering an Alternate Use RUE?

(a) An Alternate Use RUE must be issued on a competitive basis
unless BOEM determines, after public notice of the proposed Alternate
Use RUE, that there is no competitive interest.
(b) We will issue a public notice in the Federal Register to
determine if there is competitive interest in using the proposed
facility for alternate use activities. BOEM will specify a time period
for members of the public to express competitive interest.
(c) If we receive indications of competitive interest within the
published timeframe, we will proceed with a competitive offering. As
part of such competitive offering, each competing applicant must submit
a description of the types of activities proposed for the existing
facility, as well as satisfactory evidence that the competing applicant
qualifies to hold a lease or grant on the OCS, as required in Sec. Sec.
585.106 and 585.107, by a date we specify. We may request additional
information from competing applicants, as necessary, to adequately
evaluate the competing proposals.
(d) We will evaluate all competing proposals to determine whether:
(1) The proposed activities are compatible with existing activities
at the facility; and
(2) We have the expertise and resources available to regulate the
activities effectively.
(e) We will evaluate all proposals under the requirements of NEPA,
CZMA, and other applicable laws.
(f) Following our evaluation, we will select one or more acceptable
proposals for activities involving the alternate use of an existing OCS
facility, notify the competing applicants, and submit each acceptable
proposal to the lessee and owner of the existing OCS facility. If the
lessee and owner of the facility agree to accept a proposal, we will
proceed to issue an Alternate Use RUE. If

[[Page 628]]

the lessee and owner of the facility are unwilling to accept any of the
proposals that we deem acceptable, we will not issue an Alternate Use
RUE.

Sec. Sec. 585.1008-585.1009 [Reserved]

Alternate Use RUE Administration

Sec. 585.1010 How long may I conduct activities under an Alternate Use RUE?

(a) We will establish on a case-by-case basis, and set forth in the
Alternate Use RUE, the length of time for which you are authorized to
conduct activities approved in your Alternate Use RUE instrument.
(b) In establishing this term, BOEM will consider the size and scale
of the proposed alternate use activities, the type of alternate use
activities, and any other relevant considerations.
(c) BOEM may authorize renewal of Alternate Use RUEs at its
discretion.

Sec. 585.1011 What payments are required for an Alternate Use RUE?

We will establish rental or other payments for an Alternate Use RUE
on a case-by-case basis, as set forth in the Alternate Use RUE grant,
depending on our assessment of the following factors:
(a) The effect on the original OCS Lands Act approved activity;
(b) The size and scale of the proposed alternate use activities;
(c) The income, if any, expected to be generated from the proposed
alternate use activities; and
(d) The type of alternate use activities.

Sec. 585.1012 What financial assurance is required for an Alternate Use RUE?

(a) The holder of an Alternate Use RUE will be required to secure
financial assurances in an amount determined by BOEM that is sufficient
to cover all obligations under the Alternate Use RUE, including
decommissioning obligations, and must retain such financial assurance
amounts until all obligations have been fulfilled, as determined by
BOEM.
(b) We may revise financial assurance amounts, as necessary, to
ensure that there is sufficient financial assurance to secure all
obligations under the Alternate Use RUE.
(c) We may reduce the amount of the financial assurance that you
must retain if it is not necessary to cover existing obligations under
the Alternate Use RUE.

Sec. 585.1013 Is an Alternate Use RUE assignable?

(a) BOEM may authorize assignment of an Alternate Use RUE.
(b) To request assignment of an Alternate Use RUE, you must submit a
written request for assignment that includes the following information:
(1) BOEM-assigned Alternate Use RUE number;
(2) The names of both the assignor and the assignee, if applicable;
(3) The names and telephone numbers of the contacts for both the
assignor and the assignee;
(4) The names, titles, and signatures of the authorizing officials
for both the assignor and the assignee;
(5) A statement affirming that the owner of the existing OCS
facility and lessee of the lease in which the facility is located
approve of the proposed assignment and assignee;
(6) A statement that the assignee agrees to comply with and to be
bound by the terms and conditions of the Alternate Use RUE;
(7) Evidence required by Sec. 585.107 that the assignee satisfies
the requirements of Sec. 585.106; and
(8) A statement on how the assignee will comply with the financial
assurance requirements set forth in the Alternate Use RUE.
(c) The assignment takes effect on the date we approve your request.
(d) The assignor is liable for all obligations that accrue under an
Alternate Use RUE before the date we approve your assignment request. An
assignment approval by BOEM does not relieve the assignor of liability
for accrued obligations that the assignee, or a subsequent assignee,
fails to perform.
(e) The assignee and each subsequent assignee are liable for all
obligations that accrue under an Alternate Use RUE after the date we
approve the assignment request.

[[Page 629]]

Sec. 585.1014 When will BOEM suspend an Alternate Use RUE?

(a) BOEM may suspend an Alternate Use RUE if:
(1) Necessary to comply with judicial decrees;
(2) Continued activities pursuant to the Alternate Use RUE pose an
imminent threat of serious or irreparable harm or damage to natural
resources; life (including human and wildlife); property; the marine,
coastal, or human environment; or sites, structures, or objects of
historical or archaeological significance;
(3) The suspension is necessary for reasons of National security or
defense; or
(4) We have suspended or temporarily prohibited operation of the
existing OCS facility that is subject to the Alternate Use RUE, and have
determined that continued activities under the Alternate Use RUE are
unsafe or cause undue interference with the operation of the original
OCS Lands Act approved activity.
(b) A suspension will extend the term of your Alternate Use RUE
grant for the period of the suspension.

Sec. 585.1015 How do I relinquish an Alternate Use RUE?

(a) You may voluntarily surrender an Alternate Use RUE by submitting
a written request to us that includes the following:
(1) The name, address, e-mail address, and phone number of an
authorized representative;
(2) The reason you are requesting relinquishment of the Alternate
Use RUE;
(3) BOEM-assigned Alternate Use RUE number;
(4) The name of the associated OCS facility, its owner, and the
lessee for the lease in which the OCS facility is located;
(5) The name, title, and signature of your authorizing official
(which must match exactly the name, title, and signature in the BOEM
qualification records); and
(6) A statement that you will adhere to the decommissioning
requirements in the Alternate Use RUE.
(b) We will not approve your relinquishment request until you have
paid all outstanding rentals (or other payments) and fines.
(c) The relinquishment takes effect on the date we approve your
request.

Sec. 585.1016 When will an Alternate Use RUE be cancelled?

The Secretary may cancel an Alternate Use RUE if it is determined,
after notice and opportunity to be heard:
(a) You no longer qualify to hold an Alternate Use RUE;
(b) You failed to provide any additional financial assurance
required by BOEM, replace or provide additional coverage for a de-valued
bond, or replace a lapsed or forfeited bond within the prescribed time
period;
(c) Continued activity under the Alternate Use RUE is likely to
cause serious harm or damage to natural resources; life (including human
and wildlife); property; the marine, coastal, or human environment; or
sites, structures, or objects of historical or archaeological
significance;
(d) Continued activity under the Alternate Use RUE is determined to
be adversely impacting the original OCS Lands Act approved activities on
the existing OCS facility;
(e) You failed to comply with any of the terms and conditions of
your approved Alternate Use RUE or your approved plan; or
(f) You otherwise failed to comply with applicable laws or
regulations.

Sec. 585.1017 [Reserved]

Decommissioning an Alternate Use RUE

Sec. 585.1018 Who is responsible for decommissioning an OCS facility
subject to an Alternate Use RUE?

(a) The holder of an Alternate Use RUE is responsible for all
decommissioning obligations that accrue following the issuance of the
Alternate Use RUE and which pertain to the Alternate Use RUE.
(b) The lessee under the lease originally issued under 30 CFR part
250 will remain responsible for decommissioning obligations that accrued
before issuance of the Alternate Use RUE, as well as for decommissioning
obligations that accrue following issuance of the Alternate Use RUE to
the extent

[[Page 630]]

associated with continued activities authorized under other parts of
this title.

Sec. 585.1019 What are the decommissioning requirements
for an Alternate Use RUE?

(a) Decommissioning requirements will be determined by BOEM on a
case-by-case basis, and will be included in the terms of each Alternate
Use RUE.
(b) Decommissioning activities must be completed within 1 year of
termination of the Alternate Use RUE.
(c) If you fail to satisfy all decommissioning requirements within
the prescribed time period, we will call for the forfeiture of your bond
or other financial guarantee, and you will remain liable for all
accidents or damages that might result from such failure.

[[Page 631]]

SUBCHAPTER C_APPEALS

PART 590_APPEAL PROCEDURES--Table of Contents

Subpart A_Offshore Minerals Management Appeal Procedures

Sec.
590.1 What is the purpose of this subpart?
590.2 Who may appeal?
590.3 What is the time limit for filing an appeal?
590.4 How do I file an appeal?
590.5 Can I obtain an extension for filing my Notice of Appeal?
590.6 Are informal resolutions permitted?
590.7 Do I have to comply with the decision or order while my appeal is
pending?
590.8 How do I exhaust my administrative remedies?

Subpart B [Reserved]

Authority: 5 U.S.C. 301 et seq.; 31 U.S.C. 9701; 43 U.S.C. 1334.

Source: 76 FR 64623, Oct. 18, 2011, unless otherwise noted.

Subpart A_Offshore Minerals Management Appeal Procedures

Sec. 590.1 What is the purpose of this subpart?

The purpose of this subpart is to explain the procedures for appeals
of Bureau of Ocean Energy Management (BOEM) Offshore Minerals Management
(OMM) decisions and orders issued under subchapter C.

Sec. 590.2 Who may appeal?

If you are adversely affected by an OMM official's final decision or
order issued under 30 CFR chapter V, subchapter C, you may appeal that
decision or order to the Interior Board of Land Appeals (IBLA). Your
appeal must conform with the procedures found in this subpart and 43 CFR
part 4, subpart E. A request for reconsideration of a BOEM decision
concerning a lease bid, authorized in 30 CFR parts 556.47(e)(3),
581.21(a)(1), or 585.118(c), is not subject to the procedures found in
this part.

Sec. 590.3 What is the time limit for filing an appeal?

You must file your appeal within 60 days after you receive OMM's
final decision or order. The 60-day time period applies rather than the
time period provided in 43 CFR 4.411(a). A decision or order is received
on the date you sign a receipt confirming delivery or, if there is no
receipt, the date otherwise documented.

Sec. 590.4 How do I file an appeal?

For your appeal to be filed, BOEM must receive all of the following
within 60 days after you receive the decision or order:
(a) A written Notice of Appeal together with a copy of the decision
or order you are appealing in the office of the OEMM officer that issued
the decision or order. You cannot extend the 60-day period for that
office to receive your Notice of Appeal; and
(b) A nonrefundable processing fee of $150 paid with the Notice of
Appeal.
(1) You must pay electronically through the Fees for Services page
on the BOEM Web site at http://www.boem.gov, and you must include a copy
of the Pay.gov confirmation receipt page with your Notice of Appeal.
(2) You cannot extend the 60-day period for payment of the
processing fee.

[76 FR 64623, Oct. 18, 2011, as amended at 79 FR 21626, Apr. 17, 2014]

Sec. 590.5 Can I obtain an extension for filing my Notice of Appeal?

You cannot obtain an extension of time to file the Notice of Appeal.
See 43 CFR 4.411(c).

Sec. 590.6 Are informal resolutions permitted?

(a) You may seek informal resolution with the issuing officer's next
level supervisor during the 60-day period established in Sec. 590.3.
(b) Nothing in this subpart precludes resolution by settlement of
any appeal or matter pending in the administrative process after the 60-
day period established in Sec. 590.3.

[[Page 632]]

Sec. 590.7 Do I have to comply with the decision or order
while my appeal is pending?

(a) The decision or order is effective during the 60-day period for
filing an appeal under Sec. 590.3 unless:
(1) OMM notifies you that the decision or order, or some portion of
it, is suspended during this period because there is no likelihood of
immediate and irreparable harm to human life, the environment, any
mineral deposit, or property; or
(2) You post a surety bond under 30 CFR 550.1409 pending the appeal
challenging an order to pay a civil penalty.
(b) This section applies rather than 43 CFR 4.21(a) for appeals of
OMM orders.
(c) After you file your appeal, IBLA may grant a stay of a decision
or order under 43 CFR 4.21(b); however, a decision or order remains in
effect until IBLA grants your request for a stay of the decision or
order under appeal.

Sec. 590.8 How do I exhaust my administrative remedies?

(a) If you receive a decision or order issued under chapter V,
subchapter C, you must appeal that decision or order to IBLA under 43
CFR part 4, subpart E, to exhaust administrative remedies.
(b) This section does not apply if the Assistant Secretary for Land
and Minerals Management or the IBLA makes a decision or order
immediately effective notwithstanding an appeal.

Subpart B [Reserved]

PARTS 591 599 [RESERVED]

[[Page 633]]

FINDING AIDS

--------------------------------------------------------------------

A list of CFR titles, subtitles, chapters, subchapters and parts and
an alphabetical list of agencies publishing in the CFR are included in
the CFR Index and Finding Aids volume to the Code of Federal Regulations
which is published separately and revised annually.

Table of CFR Titles and Chapters
Alphabetical List of Agencies Appearing in the CFR
List of CFR Sections Affected

[[Page 635]]

Table of CFR Titles and Chapters

(Revised as of July 1, 2018)

Title 1--General Provisions

I Administrative Committee of the Federal Register
(Parts 1--49)
II Office of the Federal Register (Parts 50--299)
III Administrative Conference of the United States (Parts
300--399)
IV Miscellaneous Agencies (Parts 400--599)
VI National Capital Planning Commission (Parts 600--699)

Title 2--Grants and Agreements

Subtitle A--Office of Management and Budget Guidance
for Grants and Agreements
I Office of Management and Budget Governmentwide
Guidance for Grants and Agreements (Parts 2--199)
II Office of Management and Budget Guidance (Parts 200--
299)
Subtitle B--Federal Agency Regulations for Grants and
Agreements
III Department of Health and Human Services (Parts 300--
399)
IV Department of Agriculture (Parts 400--499)
VI Department of State (Parts 600--699)
VII Agency for International Development (Parts 700--799)
VIII Department of Veterans Affairs (Parts 800--899)
IX Department of Energy (Parts 900--999)
X Department of the Treasury (Parts 1000--1099)
XI Department of Defense (Parts 1100--1199)
XII Department of Transportation (Parts 1200--1299)
XIII Department of Commerce (Parts 1300--1399)
XIV Department of the Interior (Parts 1400--1499)
XV Environmental Protection Agency (Parts 1500--1599)
XVIII National Aeronautics and Space Administration (Parts
1800--1899)
XX United States Nuclear Regulatory Commission (Parts
2000--2099)
XXII Corporation for National and Community Service (Parts
2200--2299)
XXIII Social Security Administration (Parts 2300--2399)
XXIV Department of Housing and Urban Development (Parts
2400--2499)
XXV National Science Foundation (Parts 2500--2599)
XXVI National Archives and Records Administration (Parts
2600--2699)

[[Page 636]]

XXVII Small Business Administration (Parts 2700--2799)
XXVIII Department of Justice (Parts 2800--2899)
XXIX Department of Labor (Parts 2900--2999)
XXX Department of Homeland Security (Parts 3000--3099)
XXXI Institute of Museum and Library Services (Parts 3100--
3199)
XXXII National Endowment for the Arts (Parts 3200--3299)
XXXIII National Endowment for the Humanities (Parts 3300--
3399)
XXXIV Department of Education (Parts 3400--3499)
XXXV Export-Import Bank of the United States (Parts 3500--
3599)
XXXVI Office of National Drug Control Policy, Executive
Office of the President (Parts 3600--3699)
XXXVII Peace Corps (Parts 3700--3799)
LVIII Election Assistance Commission (Parts 5800--5899)
LIX Gulf Coast Ecosystem Restoration Council (Parts 5900--
5999)

Title 3--The President

I Executive Office of the President (Parts 100--199)

Title 4--Accounts

I Government Accountability Office (Parts 1--199)

Title 5--Administrative Personnel

I Office of Personnel Management (Parts 1--1199)
II Merit Systems Protection Board (Parts 1200--1299)
III Office of Management and Budget (Parts 1300--1399)
IV Office of Personnel Management and Office of the
Director of National Intelligence (Parts 1400--
1499)
V The International Organizations Employees Loyalty
Board (Parts 1500--1599)
VI Federal Retirement Thrift Investment Board (Parts
1600--1699)
VIII Office of Special Counsel (Parts 1800--1899)
IX Appalachian Regional Commission (Parts 1900--1999)
XI Armed Forces Retirement Home (Parts 2100--2199)
XIV Federal Labor Relations Authority, General Counsel of
the Federal Labor Relations Authority and Federal
Service Impasses Panel (Parts 2400--2499)
XVI Office of Government Ethics (Parts 2600--2699)
XXI Department of the Treasury (Parts 3100--3199)
XXII Federal Deposit Insurance Corporation (Parts 3200--
3299)
XXIII Department of Energy (Parts 3300--3399)
XXIV Federal Energy Regulatory Commission (Parts 3400--
3499)
XXV Department of the Interior (Parts 3500--3599)
XXVI Department of Defense (Parts 3600--3699)

[[Page 637]]

XXVIII Department of Justice (Parts 3800--3899)
XXIX Federal Communications Commission (Parts 3900--3999)
XXX Farm Credit System Insurance Corporation (Parts 4000--
4099)
XXXI Farm Credit Administration (Parts 4100--4199)
XXXIII Overseas Private Investment Corporation (Parts 4300--
4399)
XXXIV Securities and Exchange Commission (Parts 4400--4499)
XXXV Office of Personnel Management (Parts 4500--4599)
XXXVI Department of Homeland Security (Parts 4600--4699)
XXXVII Federal Election Commission (Parts 4700--4799)
XL Interstate Commerce Commission (Parts 5000--5099)
XLI Commodity Futures Trading Commission (Parts 5100--
5199)
XLII Department of Labor (Parts 5200--5299)
XLIII National Science Foundation (Parts 5300--5399)
XLV Department of Health and Human Services (Parts 5500--
5599)
XLVI Postal Rate Commission (Parts 5600--5699)
XLVII Federal Trade Commission (Parts 5700--5799)
XLVIII Nuclear Regulatory Commission (Parts 5800--5899)
XLIX Federal Labor Relations Authority (Parts 5900--5999)
L Department of Transportation (Parts 6000--6099)
LII Export-Import Bank of the United States (Parts 6200--
6299)
LIII Department of Education (Parts 6300--6399)
LIV Environmental Protection Agency (Parts 6400--6499)
LV National Endowment for the Arts (Parts 6500--6599)
LVI National Endowment for the Humanities (Parts 6600--
6699)
LVII General Services Administration (Parts 6700--6799)
LVIII Board of Governors of the Federal Reserve System
(Parts 6800--6899)
LIX National Aeronautics and Space Administration (Parts
6900--6999)
LX United States Postal Service (Parts 7000--7099)
LXI National Labor Relations Board (Parts 7100--7199)
LXII Equal Employment Opportunity Commission (Parts 7200--
7299)
LXIII Inter-American Foundation (Parts 7300--7399)
LXIV Merit Systems Protection Board (Parts 7400--7499)
LXV Department of Housing and Urban Development (Parts
7500--7599)
LXVI National Archives and Records Administration (Parts
7600--7699)
LXVII Institute of Museum and Library Services (Parts 7700--
7799)
LXVIII Commission on Civil Rights (Parts 7800--7899)
LXIX Tennessee Valley Authority (Parts 7900--7999)
LXX Court Services and Offender Supervision Agency for the
District of Columbia (Parts 8000--8099)
LXXI Consumer Product Safety Commission (Parts 8100--8199)
LXXIII Department of Agriculture (Parts 8300--8399)

[[Page 638]]

LXXIV Federal Mine Safety and Health Review Commission
(Parts 8400--8499)
LXXVI Federal Retirement Thrift Investment Board (Parts
8600--8699)
LXXVII Office of Management and Budget (Parts 8700--8799)
LXXX Federal Housing Finance Agency (Parts 9000--9099)
LXXXIII Special Inspector General for Afghanistan
Reconstruction (Parts 9300--9399)
LXXXIV Bureau of Consumer Financial Protection (Parts 9400--
9499)
LXXXVI National Credit Union Administration (Parts 9600--
9699)
XCVII Department of Homeland Security Human Resources
Management System (Department of Homeland
Security--Office of Personnel Management) (Parts
9700--9799)
XCVIII Council of the Inspectors General on Integrity and
Efficiency (Parts 9800--9899)
XCIX Military Compensation and Retirement Modernization
Commission (Parts 9900--9999)
C National Council on Disability (Parts 10000--10049)

Title 6--Domestic Security

I Department of Homeland Security, Office of the
Secretary (Parts 1--199)
X Privacy and Civil Liberties Oversight Board (Parts
1000--1099)

Title 7--Agriculture

Subtitle A--Office of the Secretary of Agriculture
(Parts 0--26)
Subtitle B--Regulations of the Department of
Agriculture
I Agricultural Marketing Service (Standards,
Inspections, Marketing Practices), Department of
Agriculture (Parts 27--209)
II Food and Nutrition Service, Department of Agriculture
(Parts 210--299)
III Animal and Plant Health Inspection Service, Department
of Agriculture (Parts 300--399)
IV Federal Crop Insurance Corporation, Department of
Agriculture (Parts 400--499)
V Agricultural Research Service, Department of
Agriculture (Parts 500--599)
VI Natural Resources Conservation Service, Department of
Agriculture (Parts 600--699)
VII Farm Service Agency, Department of Agriculture (Parts
700--799)
VIII Grain Inspection, Packers and Stockyards
Administration (Federal Grain Inspection Service),
Department of Agriculture (Parts 800--899)
IX Agricultural Marketing Service (Marketing Agreements
and Orders; Fruits, Vegetables, Nuts), Department
of Agriculture (Parts 900--999)

[[Page 639]]

X Agricultural Marketing Service (Marketing Agreements
and Orders; Milk), Department of Agriculture
(Parts 1000--1199)
XI Agricultural Marketing Service (Marketing Agreements
and Orders; Miscellaneous Commodities), Department
of Agriculture (Parts 1200--1299)
XIV Commodity Credit Corporation, Department of
Agriculture (Parts 1400--1499)
XV Foreign Agricultural Service, Department of
Agriculture (Parts 1500--1599)
XVI Rural Telephone Bank, Department of Agriculture (Parts
1600--1699)
XVII Rural Utilities Service, Department of Agriculture
(Parts 1700--1799)
XVIII Rural Housing Service, Rural Business-Cooperative
Service, Rural Utilities Service, and Farm Service
Agency, Department of Agriculture (Parts 1800--
2099)
XX Local Television Loan Guarantee Board (Parts 2200--
2299)
XXV Office of Advocacy and Outreach, Department of
Agriculture (Parts 2500--2599)
XXVI Office of Inspector General, Department of Agriculture
(Parts 2600--2699)
XXVII Office of Information Resources Management, Department
of Agriculture (Parts 2700--2799)
XXVIII Office of Operations, Department of Agriculture (Parts
2800--2899)
XXIX Office of Energy Policy and New Uses, Department of
Agriculture (Parts 2900--2999)
XXX Office of the Chief Financial Officer, Department of
Agriculture (Parts 3000--3099)
XXXI Office of Environmental Quality, Department of
Agriculture (Parts 3100--3199)
XXXII Office of Procurement and Property Management,
Department of Agriculture (Parts 3200--3299)
XXXIII Office of Transportation, Department of Agriculture
(Parts 3300--3399)
XXXIV National Institute of Food and Agriculture (Parts
3400--3499)
XXXV Rural Housing Service, Department of Agriculture
(Parts 3500--3599)
XXXVI National Agricultural Statistics Service, Department
of Agriculture (Parts 3600--3699)
XXXVII Economic Research Service, Department of Agriculture
(Parts 3700--3799)
XXXVIII World Agricultural Outlook Board, Department of
Agriculture (Parts 3800--3899)
XLI [Reserved]
XLII Rural Business-Cooperative Service and Rural Utilities
Service, Department of Agriculture (Parts 4200--
4299)

[[Page 640]]

Title 8--Aliens and Nationality

I Department of Homeland Security (Immigration and
Naturalization) (Parts 1--499)
V Executive Office for Immigration Review, Department of
Justice (Parts 1000--1399)

Title 9--Animals and Animal Products

I Animal and Plant Health Inspection Service, Department
of Agriculture (Parts 1--199)
II Grain Inspection, Packers and Stockyards
Administration (Packers and Stockyards Programs),
Department of Agriculture (Parts 200--299)
III Food Safety and Inspection Service, Department of
Agriculture (Parts 300--599)

Title 10--Energy

I Nuclear Regulatory Commission (Parts 0--199)
II Department of Energy (Parts 200--699)
III Department of Energy (Parts 700--999)
X Department of Energy (General Provisions) (Parts
1000--1099)
XIII Nuclear Waste Technical Review Board (Parts 1300--
1399)
XVII Defense Nuclear Facilities Safety Board (Parts 1700--
1799)
XVIII Northeast Interstate Low-Level Radioactive Waste
Commission (Parts 1800--1899)

Title 11--Federal Elections

I Federal Election Commission (Parts 1--9099)
II Election Assistance Commission (Parts 9400--9499)

Title 12--Banks and Banking

I Comptroller of the Currency, Department of the
Treasury (Parts 1--199)
II Federal Reserve System (Parts 200--299)
III Federal Deposit Insurance Corporation (Parts 300--399)
IV Export-Import Bank of the United States (Parts 400--
499)
V Office of Thrift Supervision, Department of the
Treasury (Parts 500--599)
VI Farm Credit Administration (Parts 600--699)
VII National Credit Union Administration (Parts 700--799)
VIII Federal Financing Bank (Parts 800--899)
IX Federal Housing Finance Board (Parts 900--999)
X Bureau of Consumer Financial Protection (Parts 1000--
1099)
XI Federal Financial Institutions Examination Council
(Parts 1100--1199)
XII Federal Housing Finance Agency (Parts 1200--1299)

[[Page 641]]

XIII Financial Stability Oversight Council (Parts 1300--
1399)
XIV Farm Credit System Insurance Corporation (Parts 1400--
1499)
XV Department of the Treasury (Parts 1500--1599)
XVI Office of Financial Research (Parts 1600--1699)
XVII Office of Federal Housing Enterprise Oversight,
Department of Housing and Urban Development (Parts
1700--1799)
XVIII Community Development Financial Institutions Fund,
Department of the Treasury (Parts 1800--1899)

Title 13--Business Credit and Assistance

I Small Business Administration (Parts 1--199)
III Economic Development Administration, Department of
Commerce (Parts 300--399)
IV Emergency Steel Guarantee Loan Board (Parts 400--499)
V Emergency Oil and Gas Guaranteed Loan Board (Parts
500--599)

Title 14--Aeronautics and Space

I Federal Aviation Administration, Department of
Transportation (Parts 1--199)
II Office of the Secretary, Department of Transportation
(Aviation Proceedings) (Parts 200--399)
III Commercial Space Transportation, Federal Aviation
Administration, Department of Transportation
(Parts 400--1199)
V National Aeronautics and Space Administration (Parts
1200--1299)
VI Air Transportation System Stabilization (Parts 1300--
1399)

Title 15--Commerce and Foreign Trade

Subtitle A--Office of the Secretary of Commerce (Parts
0--29)
Subtitle B--Regulations Relating to Commerce and
Foreign Trade
I Bureau of the Census, Department of Commerce (Parts
30--199)
II National Institute of Standards and Technology,
Department of Commerce (Parts 200--299)
III International Trade Administration, Department of
Commerce (Parts 300--399)
IV Foreign-Trade Zones Board, Department of Commerce
(Parts 400--499)
VII Bureau of Industry and Security, Department of
Commerce (Parts 700--799)
VIII Bureau of Economic Analysis, Department of Commerce
(Parts 800--899)
IX National Oceanic and Atmospheric Administration,
Department of Commerce (Parts 900--999)

[[Page 642]]

XI National Technical Information Service, Department of
Commerce (Parts 1100--1199)
XIII East-West Foreign Trade Board (Parts 1300--1399)
XIV Minority Business Development Agency (Parts 1400--
1499)
Subtitle C--Regulations Relating to Foreign Trade
Agreements
XX Office of the United States Trade Representative
(Parts 2000--2099)
Subtitle D--Regulations Relating to Telecommunications
and Information
XXIII National Telecommunications and Information
Administration, Department of Commerce (Parts
2300--2399) [Reserved]

Title 16--Commercial Practices

I Federal Trade Commission (Parts 0--999)
II Consumer Product Safety Commission (Parts 1000--1799)

Title 17--Commodity and Securities Exchanges

I Commodity Futures Trading Commission (Parts 1--199)
II Securities and Exchange Commission (Parts 200--399)
IV Department of the Treasury (Parts 400--499)

Title 18--Conservation of Power and Water Resources

I Federal Energy Regulatory Commission, Department of
Energy (Parts 1--399)
III Delaware River Basin Commission (Parts 400--499)
VI Water Resources Council (Parts 700--799)
VIII Susquehanna River Basin Commission (Parts 800--899)
XIII Tennessee Valley Authority (Parts 1300--1399)

Title 19--Customs Duties

I U.S. Customs and Border Protection, Department of
Homeland Security; Department of the Treasury
(Parts 0--199)
II United States International Trade Commission (Parts
200--299)
III International Trade Administration, Department of
Commerce (Parts 300--399)
IV U.S. Immigration and Customs Enforcement, Department
of Homeland Security (Parts 400--599) [Reserved]

Title 20--Employees' Benefits

I Office of Workers' Compensation Programs, Department
of Labor (Parts 1--199)
II Railroad Retirement Board (Parts 200--399)

[[Page 643]]

III Social Security Administration (Parts 400--499)
IV Employees' Compensation Appeals Board, Department of
Labor (Parts 500--599)
V Employment and Training Administration, Department of
Labor (Parts 600--699)
VI Office of Workers' Compensation Programs, Department
of Labor (Parts 700--799)
VII Benefits Review Board, Department of Labor (Parts
800--899)
VIII Joint Board for the Enrollment of Actuaries (Parts
900--999)
IX Office of the Assistant Secretary for Veterans'
Employment and Training Service, Department of
Labor (Parts 1000--1099)

Title 21--Food and Drugs

I Food and Drug Administration, Department of Health and
Human Services (Parts 1--1299)
II Drug Enforcement Administration, Department of Justice
(Parts 1300--1399)
III Office of National Drug Control Policy (Parts 1400--
1499)

Title 22--Foreign Relations

I Department of State (Parts 1--199)
II Agency for International Development (Parts 200--299)
III Peace Corps (Parts 300--399)
IV International Joint Commission, United States and
Canada (Parts 400--499)
V Broadcasting Board of Governors (Parts 500--599)
VII Overseas Private Investment Corporation (Parts 700--
799)
IX Foreign Service Grievance Board (Parts 900--999)
X Inter-American Foundation (Parts 1000--1099)
XI International Boundary and Water Commission, United
States and Mexico, United States Section (Parts
1100--1199)
XII United States International Development Cooperation
Agency (Parts 1200--1299)
XIII Millennium Challenge Corporation (Parts 1300--1399)
XIV Foreign Service Labor Relations Board; Federal Labor
Relations Authority; General Counsel of the
Federal Labor Relations Authority; and the Foreign
Service Impasse Disputes Panel (Parts 1400--1499)
XV African Development Foundation (Parts 1500--1599)
XVI Japan-United States Friendship Commission (Parts
1600--1699)
XVII United States Institute of Peace (Parts 1700--1799)

Title 23--Highways

I Federal Highway Administration, Department of
Transportation (Parts 1--999)

[[Page 644]]

II National Highway Traffic Safety Administration and
Federal Highway Administration, Department of
Transportation (Parts 1200--1299)
III National Highway Traffic Safety Administration,
Department of Transportation (Parts 1300--1399)

Title 24--Housing and Urban Development

Subtitle A--Office of the Secretary, Department of
Housing and Urban Development (Parts 0--99)
Subtitle B--Regulations Relating to Housing and Urban
Development
I Office of Assistant Secretary for Equal Opportunity,
Department of Housing and Urban Development (Parts
100--199)
II Office of Assistant Secretary for Housing-Federal
Housing Commissioner, Department of Housing and
Urban Development (Parts 200--299)
III Government National Mortgage Association, Department
of Housing and Urban Development (Parts 300--399)
IV Office of Housing and Office of Multifamily Housing
Assistance Restructuring, Department of Housing
and Urban Development (Parts 400--499)
V Office of Assistant Secretary for Community Planning
and Development, Department of Housing and Urban
Development (Parts 500--599)
VI Office of Assistant Secretary for Community Planning
and Development, Department of Housing and Urban
Development (Parts 600--699) [Reserved]
VII Office of the Secretary, Department of Housing and
Urban Development (Housing Assistance Programs and
Public and Indian Housing Programs) (Parts 700--
799)
VIII Office of the Assistant Secretary for Housing--Federal
Housing Commissioner, Department of Housing and
Urban Development (Section 8 Housing Assistance
Programs, Section 202 Direct Loan Program, Section
202 Supportive Housing for the Elderly Program and
Section 811 Supportive Housing for Persons With
Disabilities Program) (Parts 800--899)
IX Office of Assistant Secretary for Public and Indian
Housing, Department of Housing and Urban
Development (Parts 900--1699)
X Office of Assistant Secretary for Housing--Federal
Housing Commissioner, Department of Housing and
Urban Development (Interstate Land Sales
Registration Program) (Parts 1700--1799)
XII Office of Inspector General, Department of Housing and
Urban Development (Parts 2000--2099)
XV Emergency Mortgage Insurance and Loan Programs,
Department of Housing and Urban Development (Parts
2700--2799) [Reserved]
XX Office of Assistant Secretary for Housing--Federal
Housing Commissioner, Department of Housing and
Urban Development (Parts 3200--3899)

[[Page 645]]

XXIV Board of Directors of the HOPE for Homeowners Program
(Parts 4000--4099) [Reserved]
XXV Neighborhood Reinvestment Corporation (Parts 4100--
4199)

Title 25--Indians

I Bureau of Indian Affairs, Department of the Interior
(Parts 1--299)
II Indian Arts and Crafts Board, Department of the
Interior (Parts 300--399)
III National Indian Gaming Commission, Department of the
Interior (Parts 500--599)
IV Office of Navajo and Hopi Indian Relocation (Parts
700--899)
V Bureau of Indian Affairs, Department of the Interior,
and Indian Health Service, Department of Health
and Human Services (Parts 900--999)
VI Office of the Assistant Secretary, Indian Affairs,
Department of the Interior (Parts 1000--1199)
VII Office of the Special Trustee for American Indians,
Department of the Interior (Parts 1200--1299)

Title 26--Internal Revenue

I Internal Revenue Service, Department of the Treasury
(Parts 1--End)

Title 27--Alcohol, Tobacco Products and Firearms

I Alcohol and Tobacco Tax and Trade Bureau, Department
of the Treasury (Parts 1--399)
II Bureau of Alcohol, Tobacco, Firearms, and Explosives,
Department of Justice (Parts 400--699)

Title 28--Judicial Administration

I Department of Justice (Parts 0--299)
III Federal Prison Industries, Inc., Department of Justice
(Parts 300--399)
V Bureau of Prisons, Department of Justice (Parts 500--
599)
VI Offices of Independent Counsel, Department of Justice
(Parts 600--699)
VII Office of Independent Counsel (Parts 700--799)
VIII Court Services and Offender Supervision Agency for the
District of Columbia (Parts 800--899)
IX National Crime Prevention and Privacy Compact Council
(Parts 900--999)
XI Department of Justice and Department of State (Parts
1100--1199)

[[Page 646]]

Title 29--Labor

Subtitle A--Office of the Secretary of Labor (Parts
0--99)
Subtitle B--Regulations Relating to Labor
I National Labor Relations Board (Parts 100--199)
II Office of Labor-Management Standards, Department of
Labor (Parts 200--299)
III National Railroad Adjustment Board (Parts 300--399)
IV Office of Labor-Management Standards, Department of
Labor (Parts 400--499)
V Wage and Hour Division, Department of Labor (Parts
500--899)
IX Construction Industry Collective Bargaining Commission
(Parts 900--999)
X National Mediation Board (Parts 1200--1299)
XII Federal Mediation and Conciliation Service (Parts
1400--1499)
XIV Equal Employment Opportunity Commission (Parts 1600--
1699)
XVII Occupational Safety and Health Administration,
Department of Labor (Parts 1900--1999)
XX Occupational Safety and Health Review Commission
(Parts 2200--2499)
XXV Employee Benefits Security Administration, Department
of Labor (Parts 2500--2599)
XXVII Federal Mine Safety and Health Review Commission
(Parts 2700--2799)
XL Pension Benefit Guaranty Corporation (Parts 4000--
4999)

Title 30--Mineral Resources

I Mine Safety and Health Administration, Department of
Labor (Parts 1--199)
II Bureau of Safety and Environmental Enforcement,
Department of the Interior (Parts 200--299)
IV Geological Survey, Department of the Interior (Parts
400--499)
V Bureau of Ocean Energy Management, Department of the
Interior (Parts 500--599)
VII Office of Surface Mining Reclamation and Enforcement,
Department of the Interior (Parts 700--999)
XII Office of Natural Resources Revenue, Department of the
Interior (Parts 1200--1299)

Title 31--Money and Finance: Treasury

Subtitle A--Office of the Secretary of the Treasury
(Parts 0--50)
Subtitle B--Regulations Relating to Money and Finance
I Monetary Offices, Department of the Treasury (Parts
51--199)
II Fiscal Service, Department of the Treasury (Parts
200--399)
IV Secret Service, Department of the Treasury (Parts
400--499)
V Office of Foreign Assets Control, Department of the
Treasury (Parts 500--599)

[[Page 647]]

VI Bureau of Engraving and Printing, Department of the
Treasury (Parts 600--699)
VII Federal Law Enforcement Training Center, Department of
the Treasury (Parts 700--799)
VIII Office of Investment Security, Department of the
Treasury (Parts 800--899)
IX Federal Claims Collection Standards (Department of the
Treasury--Department of Justice) (Parts 900--999)
X Financial Crimes Enforcement Network, Department of
the Treasury (Parts 1000--1099)

Title 32--National Defense

Subtitle A--Department of Defense
I Office of the Secretary of Defense (Parts 1--399)
V Department of the Army (Parts 400--699)
VI Department of the Navy (Parts 700--799)
VII Department of the Air Force (Parts 800--1099)
Subtitle B--Other Regulations Relating to National
Defense
XII Defense Logistics Agency (Parts 1200--1299)
XVI Selective Service System (Parts 1600--1699)
XVII Office of the Director of National Intelligence (Parts
1700--1799)
XVIII National Counterintelligence Center (Parts 1800--1899)
XIX Central Intelligence Agency (Parts 1900--1999)
XX Information Security Oversight Office, National
Archives and Records Administration (Parts 2000--
2099)
XXI National Security Council (Parts 2100--2199)
XXIV Office of Science and Technology Policy (Parts 2400--
2499)
XXVII Office for Micronesian Status Negotiations (Parts
2700--2799)
XXVIII Office of the Vice President of the United States
(Parts 2800--2899)

Title 33--Navigation and Navigable Waters

I Coast Guard, Department of Homeland Security (Parts
1--199)
II Corps of Engineers, Department of the Army, Department
of Defense (Parts 200--399)
IV Saint Lawrence Seaway Development Corporation,
Department of Transportation (Parts 400--499)

Title 34--Education

Subtitle A--Office of the Secretary, Department of
Education (Parts 1--99)
Subtitle B--Regulations of the Offices of the
Department of Education
I Office for Civil Rights, Department of Education
(Parts 100--199)

[[Page 648]]

II Office of Elementary and Secondary Education,
Department of Education (Parts 200--299)
III Office of Special Education and Rehabilitative
Services, Department of Education (Parts 300--399)
IV Office of Career, Technical and Adult Education,
Department of Education (Parts 400--499)
V Office of Bilingual Education and Minority Languages
Affairs, Department of Education (Parts 500--599)
[Reserved]
VI Office of Postsecondary Education, Department of
Education (Parts 600--699)
VII Office of Educational Research and Improvement,
Department of Education (Parts 700--799)
[Reserved]
Subtitle C--Regulations Relating to Education
XI (Parts 1100--1199) [Reserved]
XII National Council on Disability (Parts 1200--1299)

Title 35 [Reserved]

Title 36--Parks, Forests, and Public Property

I National Park Service, Department of the Interior
(Parts 1--199)
II Forest Service, Department of Agriculture (Parts 200--
299)
III Corps of Engineers, Department of the Army (Parts
300--399)
IV American Battle Monuments Commission (Parts 400--499)
V Smithsonian Institution (Parts 500--599)
VI [Reserved]
VII Library of Congress (Parts 700--799)
VIII Advisory Council on Historic Preservation (Parts 800--
899)
IX Pennsylvania Avenue Development Corporation (Parts
900--999)
X Presidio Trust (Parts 1000--1099)
XI Architectural and Transportation Barriers Compliance
Board (Parts 1100--1199)
XII National Archives and Records Administration (Parts
1200--1299)
XV Oklahoma City National Memorial Trust (Parts 1500--
1599)
XVI Morris K. Udall Scholarship and Excellence in National
Environmental Policy Foundation (Parts 1600--1699)

Title 37--Patents, Trademarks, and Copyrights

I United States Patent and Trademark Office, Department
of Commerce (Parts 1--199)
II U.S. Copyright Office, Library of Congress (Parts
200--299)
III Copyright Royalty Board, Library of Congress (Parts
300--399)
IV National Institute of Standards and Technology,
Department of Commerce (Parts 400--599)

[[Page 649]]

Title 38--Pensions, Bonuses, and Veterans' Relief

I Department of Veterans Affairs (Parts 0--199)
II Armed Forces Retirement Home (Parts 200--299)

Title 39--Postal Service

I United States Postal Service (Parts 1--999)
III Postal Regulatory Commission (Parts 3000--3099)

Title 40--Protection of Environment

I Environmental Protection Agency (Parts 1--1099)
IV Environmental Protection Agency and Department of
Justice (Parts 1400--1499)
V Council on Environmental Quality (Parts 1500--1599)
VI Chemical Safety and Hazard Investigation Board (Parts
1600--1699)
VII Environmental Protection Agency and Department of
Defense; Uniform National Discharge Standards for
Vessels of the Armed Forces (Parts 1700--1799)
VIII Gulf Coast Ecosystem Restoration Council (Parts 1800--
1899)

Title 41--Public Contracts and Property Management

Subtitle A--Federal Procurement Regulations System
[Note]
Subtitle B--Other Provisions Relating to Public
Contracts
50 Public Contracts, Department of Labor (Parts 50-1--50-
999)
51 Committee for Purchase From People Who Are Blind or
Severely Disabled (Parts 51-1--51-99)
60 Office of Federal Contract Compliance Programs, Equal
Employment Opportunity, Department of Labor (Parts
60-1--60-999)
61 Office of the Assistant Secretary for Veterans'
Employment and Training Service, Department of
Labor (Parts 61-1--61-999)
62--100 [Reserved]
Subtitle C--Federal Property Management Regulations
System
101 Federal Property Management Regulations (Parts 101-1--
101-99)
102 Federal Management Regulation (Parts 102-1--102-299)
103--104 [Reserved]
105 General Services Administration (Parts 105-1--105-999)
109 Department of Energy Property Management Regulations
(Parts 109-1--109-99)
114 Department of the Interior (Parts 114-1--114-99)
115 Environmental Protection Agency (Parts 115-1--115-99)
128 Department of Justice (Parts 128-1--128-99)
129--200 [Reserved]
Subtitle D--Other Provisions Relating to Property
Management [Reserved]

[[Page 650]]

Subtitle E--Federal Information Resources Management
Regulations System [Reserved]
Subtitle F--Federal Travel Regulation System
300 General (Parts 300-1--300-99)
301 Temporary Duty (TDY) Travel Allowances (Parts 301-1--
301-99)
302 Relocation Allowances (Parts 302-1--302-99)
303 Payment of Expenses Connected with the Death of
Certain Employees (Part 303-1--303-99)
304 Payment of Travel Expenses from a Non-Federal Source
(Parts 304-1--304-99)

Title 42--Public Health

I Public Health Service, Department of Health and Human
Services (Parts 1--199)
II--III [Reserved]
IV Centers for Medicare & Medicaid Services, Department
of Health and Human Services (Parts 400--699)
V Office of Inspector General-Health Care, Department of
Health and Human Services (Parts 1000--1099)

Title 43--Public Lands: Interior

Subtitle A--Office of the Secretary of the Interior
(Parts 1--199)
Subtitle B--Regulations Relating to Public Lands
I Bureau of Reclamation, Department of the Interior
(Parts 400--999)
II Bureau of Land Management, Department of the Interior
(Parts 1000--9999)
III Utah Reclamation Mitigation and Conservation
Commission (Parts 10000--10099)

Title 44--Emergency Management and Assistance

I Federal Emergency Management Agency, Department of
Homeland Security (Parts 0--399)
IV Department of Commerce and Department of
Transportation (Parts 400--499)

Title 45--Public Welfare

Subtitle A--Department of Health and Human Services
(Parts 1--199)
Subtitle B--Regulations Relating to Public Welfare
II Office of Family Assistance (Assistance Programs),
Administration for Children and Families,
Department of Health and Human Services (Parts
200--299)

[[Page 651]]

III Office of Child Support Enforcement (Child Support
Enforcement Program), Administration for Children
and Families, Department of Health and Human
Services (Parts 300--399)
IV Office of Refugee Resettlement, Administration for
Children and Families, Department of Health and
Human Services (Parts 400--499)
V Foreign Claims Settlement Commission of the United
States, Department of Justice (Parts 500--599)
VI National Science Foundation (Parts 600--699)
VII Commission on Civil Rights (Parts 700--799)
VIII Office of Personnel Management (Parts 800--899)
IX Denali Commission (Parts 900--999)
X Office of Community Services, Administration for
Children and Families, Department of Health and
Human Services (Parts 1000--1099)
XI National Foundation on the Arts and the Humanities
(Parts 1100--1199)
XII Corporation for National and Community Service (Parts
1200--1299)
XIII Administration for Children and Families, Department
of Health and Human Services (Parts 1300--1399)
XVI Legal Services Corporation (Parts 1600--1699)
XVII National Commission on Libraries and Information
Science (Parts 1700--1799)
XVIII Harry S. Truman Scholarship Foundation (Parts 1800--
1899)
XXI Commission of Fine Arts (Parts 2100--2199)
XXIII Arctic Research Commission (Parts 2300--2399)
XXIV James Madison Memorial Fellowship Foundation (Parts
2400--2499)
XXV Corporation for National and Community Service (Parts
2500--2599)

Title 46--Shipping

I Coast Guard, Department of Homeland Security (Parts
1--199)
II Maritime Administration, Department of Transportation
(Parts 200--399)
III Coast Guard (Great Lakes Pilotage), Department of
Homeland Security (Parts 400--499)
IV Federal Maritime Commission (Parts 500--599)

Title 47--Telecommunication

I Federal Communications Commission (Parts 0--199)
II Office of Science and Technology Policy and National
Security Council (Parts 200--299)
III National Telecommunications and Information
Administration, Department of Commerce (Parts
300--399)

[[Page 652]]

IV National Telecommunications and Information
Administration, Department of Commerce, and
National Highway Traffic Safety Administration,
Department of Transportation (Parts 400--499)
V The First Responder Network Authority (Parts 500--599)

Title 48--Federal Acquisition Regulations System

1 Federal Acquisition Regulation (Parts 1--99)
2 Defense Acquisition Regulations System, Department of
Defense (Parts 200--299)
3 Department of Health and Human Services (Parts 300--
399)
4 Department of Agriculture (Parts 400--499)
5 General Services Administration (Parts 500--599)
6 Department of State (Parts 600--699)
7 Agency for International Development (Parts 700--799)
8 Department of Veterans Affairs (Parts 800--899)
9 Department of Energy (Parts 900--999)
10 Department of the Treasury (Parts 1000--1099)
12 Department of Transportation (Parts 1200--1299)
13 Department of Commerce (Parts 1300--1399)
14 Department of the Interior (Parts 1400--1499)
15 Environmental Protection Agency (Parts 1500--1599)
16 Office of Personnel Management, Federal Employees
Health Benefits Acquisition Regulation (Parts
1600--1699)
17 Office of Personnel Management (Parts 1700--1799)
18 National Aeronautics and Space Administration (Parts
1800--1899)
19 Broadcasting Board of Governors (Parts 1900--1999)
20 Nuclear Regulatory Commission (Parts 2000--2099)
21 Office of Personnel Management, Federal Employees
Group Life Insurance Federal Acquisition
Regulation (Parts 2100--2199)
23 Social Security Administration (Parts 2300--2399)
24 Department of Housing and Urban Development (Parts
2400--2499)
25 National Science Foundation (Parts 2500--2599)
28 Department of Justice (Parts 2800--2899)
29 Department of Labor (Parts 2900--2999)
30 Department of Homeland Security, Homeland Security
Acquisition Regulation (HSAR) (Parts 3000--3099)
34 Department of Education Acquisition Regulation (Parts
3400--3499)
51 Department of the Army Acquisition Regulations (Parts
5100--5199)
52 Department of the Navy Acquisition Regulations (Parts
5200--5299)
53 Department of the Air Force Federal Acquisition
Regulation Supplement (Parts 5300--5399)
[Reserved]

[[Page 653]]

54 Defense Logistics Agency, Department of Defense (Parts
5400--5499)
57 African Development Foundation (Parts 5700--5799)
61 Civilian Board of Contract Appeals, General Services
Administration (Parts 6100--6199)
99 Cost Accounting Standards Board, Office of Federal
Procurement Policy, Office of Management and
Budget (Parts 9900--9999)

Title 49--Transportation

Subtitle A--Office of the Secretary of Transportation
(Parts 1--99)
Subtitle B--Other Regulations Relating to
Transportation
I Pipeline and Hazardous Materials Safety
Administration, Department of Transportation
(Parts 100--199)
II Federal Railroad Administration, Department of
Transportation (Parts 200--299)
III Federal Motor Carrier Safety Administration,
Department of Transportation (Parts 300--399)
IV Coast Guard, Department of Homeland Security (Parts
400--499)
V National Highway Traffic Safety Administration,
Department of Transportation (Parts 500--599)
VI Federal Transit Administration, Department of
Transportation (Parts 600--699)
VII National Railroad Passenger Corporation (AMTRAK)
(Parts 700--799)
VIII National Transportation Safety Board (Parts 800--999)
X Surface Transportation Board (Parts 1000--1399)
XI Research and Innovative Technology Administration,
Department of Transportation (Parts 1400--1499)
[Reserved]
XII Transportation Security Administration, Department of
Homeland Security (Parts 1500--1699)

Title 50--Wildlife and Fisheries

I United States Fish and Wildlife Service, Department of
the Interior (Parts 1--199)
II National Marine Fisheries Service, National Oceanic
and Atmospheric Administration, Department of
Commerce (Parts 200--299)
III International Fishing and Related Activities (Parts
300--399)
IV Joint Regulations (United States Fish and Wildlife
Service, Department of the Interior and National
Marine Fisheries Service, National Oceanic and
Atmospheric Administration, Department of
Commerce); Endangered Species Committee
Regulations (Parts 400--499)
V Marine Mammal Commission (Parts 500--599)

[[Page 654]]

VI Fishery Conservation and Management, National Oceanic
and Atmospheric Administration, Department of
Commerce (Parts 600--699)

[[Page 655]]

Alphabetical List of Agencies Appearing in the CFR

(Revised as of July 1, 2018)

CFR Title, Subtitle or
Agency Chapter

Administrative Committee of the Federal Register 1, I
Administrative Conference of the United States 1, III
Advisory Council on Historic Preservation 36, VIII
Advocacy and Outreach, Office of 7, XXV
Afghanistan Reconstruction, Special Inspector 5, LXXXIII
General for
African Development Foundation 22, XV
Federal Acquisition Regulation 48, 57
Agency for International Development 2, VII; 22, II
Federal Acquisition Regulation 48, 7
Agricultural Marketing Service 7, I, IX, X, XI
Agricultural Research Service 7, V
Agriculture, Department of 2, IV; 5, LXXIII
Advocacy and Outreach, Office of 7, XXV
Agricultural Marketing Service 7, I, IX, X, XI
Agricultural Research Service 7, V
Animal and Plant Health Inspection Service 7, III; 9, I
Chief Financial Officer, Office of 7, XXX
Commodity Credit Corporation 7, XIV
Economic Research Service 7, XXXVII
Energy Policy and New Uses, Office of 2, IX; 7, XXIX
Environmental Quality, Office of 7, XXXI
Farm Service Agency 7, VII, XVIII
Federal Acquisition Regulation 48, 4
Federal Crop Insurance Corporation 7, IV
Food and Nutrition Service 7, II
Food Safety and Inspection Service 9, III
Foreign Agricultural Service 7, XV
Forest Service 36, II
Grain Inspection, Packers and Stockyards 7, VIII; 9, II
Administration
Information Resources Management, Office of 7, XXVII
Inspector General, Office of 7, XXVI
National Agricultural Library 7, XLI
National Agricultural Statistics Service 7, XXXVI
National Institute of Food and Agriculture 7, XXXIV
Natural Resources Conservation Service 7, VI
Operations, Office of 7, XXVIII
Procurement and Property Management, Office of 7, XXXII
Rural Business-Cooperative Service 7, XVIII, XLII
Rural Development Administration 7, XLII
Rural Housing Service 7, XVIII, XXXV
Rural Telephone Bank 7, XVI
Rural Utilities Service 7, XVII, XVIII, XLII
Secretary of Agriculture, Office of 7, Subtitle A
Transportation, Office of 7, XXXIII
World Agricultural Outlook Board 7, XXXVIII
Air Force, Department of 32, VII
Federal Acquisition Regulation Supplement 48, 53
Air Transportation Stabilization Board 14, VI
Alcohol and Tobacco Tax and Trade Bureau 27, I
Alcohol, Tobacco, Firearms, and Explosives, 27, II
Bureau of
AMTRAK 49, VII
American Battle Monuments Commission 36, IV
American Indians, Office of the Special Trustee 25, VII

[[Page 656]]

Animal and Plant Health Inspection Service 7, III; 9, I
Appalachian Regional Commission 5, IX
Architectural and Transportation Barriers 36, XI
Compliance Board
Arctic Research Commission 45, XXIII
Armed Forces Retirement Home 5, XI
Army, Department of 32, V
Engineers, Corps of 33, II; 36, III
Federal Acquisition Regulation 48, 51
Bilingual Education and Minority Languages 34, V
Affairs, Office of
Blind or Severely Disabled, Committee for 41, 51
Purchase from People Who Are
Broadcasting Board of Governors 22, V
Federal Acquisition Regulation 48, 19
Career, Technical and Adult Education, Office of 34, IV
Census Bureau 15, I
Centers for Medicare & Medicaid Services 42, IV
Central Intelligence Agency 32, XIX
Chemical Safety and Hazardous Investigation 40, VI
Board
Chief Financial Officer, Office of 7, XXX
Child Support Enforcement, Office of 45, III
Children and Families, Administration for 45, II, III, IV, X, XIII
Civil Rights, Commission on 5, LXVIII; 45, VII
Civil Rights, Office for 34, I
Council of the Inspectors General on Integrity 5, XCVIII
and Efficiency
Court Services and Offender Supervision Agency 5, LXX
for the District of Columbia
Coast Guard 33, I; 46, I; 49, IV
Coast Guard (Great Lakes Pilotage) 46, III
Commerce, Department of 2, XIII; 44, IV; 50, VI
Census Bureau 15, I
Economic Analysis, Bureau of 15, VIII
Economic Development Administration 13, III
Emergency Management and Assistance 44, IV
Federal Acquisition Regulation 48, 13
Foreign-Trade Zones Board 15, IV
Industry and Security, Bureau of 15, VII
International Trade Administration 15, III; 19, III
National Institute of Standards and Technology 15, XI; 37, IV
National Marine Fisheries Service 50, II, IV
National Oceanic and Atmospheric 15, IX; 50, II, III, IV,
Administration VI
National Technical Information Service 15, XI
National Telecommunications and Information 15, XXIII; 47, III, IV
Administration
National Weather Service 15, IX
Patent and Trademark Office, United States 37, I
Secretary of Commerce, Office of 15, Subtitle A
Commercial Space Transportation 14, III
Commodity Credit Corporation 7, XIV
Commodity Futures Trading Commission 5, XLI; 17, I
Community Planning and Development, Office of 24, V, VI
Assistant Secretary for
Community Services, Office of 45, X
Comptroller of the Currency 12, I
Construction Industry Collective Bargaining 29, IX
Commission
Consumer Financial Protection Bureau 5, LXXXIV; 12, X
Consumer Product Safety Commission 5, LXXI; 16, II
Copyright Royalty Board 37, III
Corporation for National and Community Service 2, XXII; 45, XII, XXV
Cost Accounting Standards Board 48, 99
Council on Environmental Quality 40, V
Court Services and Offender Supervision Agency 5, LXX; 28, VIII
for the District of Columbia
Customs and Border Protection 19, I
Defense Contract Audit Agency 32, I
Defense, Department of 2, XI; 5, XXVI; 32,
Subtitle A; 40, VII
Advanced Research Projects Agency 32, I

[[Page 657]]

Air Force Department 32, VII
Army Department 32, V; 33, II; 36, III;
48, 51
Defense Acquisition Regulations System 48, 2
Defense Intelligence Agency 32, I
Defense Logistics Agency 32, I, XII; 48, 54
Engineers, Corps of 33, II; 36, III
National Imagery and Mapping Agency 32, I
Navy Department 32, VI; 48, 52
Secretary of Defense, Office of 2, XI; 32, I
Defense Contract Audit Agency 32, I
Defense Intelligence Agency 32, I
Defense Logistics Agency 32, XII; 48, 54
Defense Nuclear Facilities Safety Board 10, XVII
Delaware River Basin Commission 18, III
Denali Commission 45, IX
Disability, National Council on 5, C; 34, XII
District of Columbia, Court Services and 5, LXX; 28, VIII
Offender Supervision Agency for the
Drug Enforcement Administration 21, II
East-West Foreign Trade Board 15, XIII
Economic Analysis, Bureau of 15, VIII
Economic Development Administration 13, III
Economic Research Service 7, XXXVII
Education, Department of 2, XXXIV; 5, LIII
Bilingual Education and Minority Languages 34, V
Affairs, Office of
Career, Technical, and Adult Education, Office 34, IV
of
Civil Rights, Office for 34, I
Educational Research and Improvement, Office 34, VII
of
Elementary and Secondary Education, Office of 34, II
Federal Acquisition Regulation 48, 34
Postsecondary Education, Office of 34, VI
Secretary of Education, Office of 34, Subtitle A
Special Education and Rehabilitative Services, 34, III
Office of
Educational Research and Improvement, Office of 34, VII
Election Assistance Commission 2, LVIII; 11, II
Elementary and Secondary Education, Office of 34, II
Emergency Oil and Gas Guaranteed Loan Board 13, V
Emergency Steel Guarantee Loan Board 13, IV
Employee Benefits Security Administration 29, XXV
Employees' Compensation Appeals Board 20, IV
Employees Loyalty Board 5, V
Employment and Training Administration 20, V
Employment Policy, National Commission for 1, IV
Employment Standards Administration 20, VI
Endangered Species Committee 50, IV
Energy, Department of 2, IX; 5, XXIII; 10, II,
III, X
Federal Acquisition Regulation 48, 9
Federal Energy Regulatory Commission 5, XXIV; 18, I
Property Management Regulations 41, 109
Energy, Office of 7, XXIX
Engineers, Corps of 33, II; 36, III
Engraving and Printing, Bureau of 31, VI
Environmental Protection Agency 2, XV; 5, LIV; 40, I, IV,
VII
Federal Acquisition Regulation 48, 15
Property Management Regulations 41, 115
Environmental Quality, Office of 7, XXXI
Equal Employment Opportunity Commission 5, LXII; 29, XIV
Equal Opportunity, Office of Assistant Secretary 24, I
for
Executive Office of the President 3, I
Environmental Quality, Council on 40, V
Management and Budget, Office of 2, Subtitle A; 5, III,
LXXVII; 14, VI; 48, 99
National Drug Control Policy, Office of 2, XXXVI; 21, III

[[Page 658]]

National Security Council 32, XXI; 47, 2
Presidential Documents 3
Science and Technology Policy, Office of 32, XXIV; 47, II
Trade Representative, Office of the United 15, XX
States
Export-Import Bank of the United States 2, XXXV; 5, LII; 12, IV
Family Assistance, Office of 45, II
Farm Credit Administration 5, XXXI; 12, VI
Farm Credit System Insurance Corporation 5, XXX; 12, XIV
Farm Service Agency 7, VII, XVIII
Federal Acquisition Regulation 48, 1
Federal Aviation Administration 14, I
Commercial Space Transportation 14, III
Federal Claims Collection Standards 31, IX
Federal Communications Commission 5, XXIX; 47, I
Federal Contract Compliance Programs, Office of 41, 60
Federal Crop Insurance Corporation 7, IV
Federal Deposit Insurance Corporation 5, XXII; 12, III
Federal Election Commission 5, XXXVII; 11, I
Federal Emergency Management Agency 44, I
Federal Employees Group Life Insurance Federal 48, 21
Acquisition Regulation
Federal Employees Health Benefits Acquisition 48, 16
Regulation
Federal Energy Regulatory Commission 5, XXIV; 18, I
Federal Financial Institutions Examination 12, XI
Council
Federal Financing Bank 12, VIII
Federal Highway Administration 23, I, II
Federal Home Loan Mortgage Corporation 1, IV
Federal Housing Enterprise Oversight Office 12, XVII
Federal Housing Finance Agency 5, LXXX; 12, XII
Federal Housing Finance Board 12, IX
Federal Labor Relations Authority 5, XIV, XLIX; 22, XIV
Federal Law Enforcement Training Center 31, VII
Federal Management Regulation 41, 102
Federal Maritime Commission 46, IV
Federal Mediation and Conciliation Service 29, XII
Federal Mine Safety and Health Review Commission 5, LXXIV; 29, XXVII
Federal Motor Carrier Safety Administration 49, III
Federal Prison Industries, Inc. 28, III
Federal Procurement Policy Office 48, 99
Federal Property Management Regulations 41, 101
Federal Railroad Administration 49, II
Federal Register, Administrative Committee of 1, I
Federal Register, Office of 1, II
Federal Reserve System 12, II
Board of Governors 5, LVIII
Federal Retirement Thrift Investment Board 5, VI, LXXVI
Federal Service Impasses Panel 5, XIV
Federal Trade Commission 5, XLVII; 16, I
Federal Transit Administration 49, VI
Federal Travel Regulation System 41, Subtitle F
Financial Crimes Enforcement Network 31, X
Financial Research Office 12, XVI
Financial Stability Oversight Council 12, XIII
Fine Arts, Commission of 45, XXI
Fiscal Service 31, II
Fish and Wildlife Service, United States 50, I, IV
Food and Drug Administration 21, I
Food and Nutrition Service 7, II
Food Safety and Inspection Service 9, III
Foreign Agricultural Service 7, XV
Foreign Assets Control, Office of 31, V
Foreign Claims Settlement Commission of the 45, V
United States
Foreign Service Grievance Board 22, IX
Foreign Service Impasse Disputes Panel 22, XIV
Foreign Service Labor Relations Board 22, XIV
Foreign-Trade Zones Board 15, IV
Forest Service 36, II

[[Page 659]]

General Services Administration 5, LVII; 41, 105
Contract Appeals, Board of 48, 61
Federal Acquisition Regulation 48, 5
Federal Management Regulation 41, 102
Federal Property Management Regulations 41, 101
Federal Travel Regulation System 41, Subtitle F
General 41, 300
Payment From a Non-Federal Source for Travel 41, 304
Expenses
Payment of Expenses Connected With the Death 41, 303
of Certain Employees
Relocation Allowances 41, 302
Temporary Duty (TDY) Travel Allowances 41, 301
Geological Survey 30, IV
Government Accountability Office 4, I
Government Ethics, Office of 5, XVI
Government National Mortgage Association 24, III
Grain Inspection, Packers and Stockyards 7, VIII; 9, II
Administration
Gulf Coast Ecosystem Restoration Council 2, LIX; 40, VIII
Harry S. Truman Scholarship Foundation 45, XVIII
Health and Human Services, Department of 2, III; 5, XLV; 45,
Subtitle A
Centers for Medicare & Medicaid Services 42, IV
Child Support Enforcement, Office of 45, III
Children and Families, Administration for 45, II, III, IV, X, XIII
Community Services, Office of 45, X
Family Assistance, Office of 45, II
Federal Acquisition Regulation 48, 3
Food and Drug Administration 21, I
Indian Health Service 25, V
Inspector General (Health Care), Office of 42, V
Public Health Service 42, I
Refugee Resettlement, Office of 45, IV
Homeland Security, Department of 2, XXX; 5, XXXVI; 6, I; 8,
I
Coast Guard 33, I; 46, I; 49, IV
Coast Guard (Great Lakes Pilotage) 46, III
Customs and Border Protection 19, I
Federal Emergency Management Agency 44, I
Human Resources Management and Labor Relations 5, XCVII
Systems
Immigration and Customs Enforcement Bureau 19, IV
Transportation Security Administration 49, XII
HOPE for Homeowners Program, Board of Directors 24, XXIV
of
Housing and Urban Development, Department of 2, XXIV; 5, LXV; 24,
Subtitle B
Community Planning and Development, Office of 24, V, VI
Assistant Secretary for
Equal Opportunity, Office of Assistant 24, I
Secretary for
Federal Acquisition Regulation 48, 24
Federal Housing Enterprise Oversight, Office 12, XVII
of
Government National Mortgage Association 24, III
Housing--Federal Housing Commissioner, Office 24, II, VIII, X, XX
of Assistant Secretary for
Housing, Office of, and Multifamily Housing 24, IV
Assistance Restructuring, Office of
Inspector General, Office of 24, XII
Public and Indian Housing, Office of Assistant 24, IX
Secretary for
Secretary, Office of 24, Subtitle A, VII
Housing--Federal Housing Commissioner, Office of 24, II, VIII, X, XX
Assistant Secretary for
Housing, Office of, and Multifamily Housing 24, IV
Assistance Restructuring, Office of
Immigration and Customs Enforcement Bureau 19, IV
Immigration Review, Executive Office for 8, V
Independent Counsel, Office of 28, VII
Independent Counsel, Offices of 28, VI
Indian Affairs, Bureau of 25, I, V

[[Page 660]]

Indian Affairs, Office of the Assistant 25, VI
Secretary
Indian Arts and Crafts Board 25, II
Indian Health Service 25, V
Industry and Security, Bureau of 15, VII
Information Resources Management, Office of 7, XXVII
Information Security Oversight Office, National 32, XX
Archives and Records Administration
Inspector General
Agriculture Department 7, XXVI
Health and Human Services Department 42, V
Housing and Urban Development Department 24, XII, XV
Institute of Peace, United States 22, XVII
Inter-American Foundation 5, LXIII; 22, X
Interior, Department of 2, XIV
American Indians, Office of the Special 25, VII
Trustee
Endangered Species Committee 50, IV
Federal Acquisition Regulation 48, 14
Federal Property Management Regulations System 41, 114
Fish and Wildlife Service, United States 50, I, IV
Geological Survey 30, IV
Indian Affairs, Bureau of 25, I, V
Indian Affairs, Office of the Assistant 25, VI
Secretary
Indian Arts and Crafts Board 25, II
Land Management, Bureau of 43, II
National Indian Gaming Commission 25, III
National Park Service 36, I
Natural Resource Revenue, Office of 30, XII
Ocean Energy Management, Bureau of 30, V
Reclamation, Bureau of 43, I
Safety and Enforcement Bureau, Bureau of 30, II
Secretary of the Interior, Office of 2, XIV; 43, Subtitle A
Surface Mining Reclamation and Enforcement, 30, VII
Office of
Internal Revenue Service 26, I
International Boundary and Water Commission, 22, XI
United States and Mexico, United States
Section
International Development, United States Agency 22, II
for
Federal Acquisition Regulation 48, 7
International Development Cooperation Agency, 22, XII
United States
International Joint Commission, United States 22, IV
and Canada
International Organizations Employees Loyalty 5, V
Board
International Trade Administration 15, III; 19, III
International Trade Commission, United States 19, II
Interstate Commerce Commission 5, XL
Investment Security, Office of 31, VIII
James Madison Memorial Fellowship Foundation 45, XXIV
Japan-United States Friendship Commission 22, XVI
Joint Board for the Enrollment of Actuaries 20, VIII
Justice, Department of 2, XXVIII; 5, XXVIII; 28,
I, XI; 40, IV
Alcohol, Tobacco, Firearms, and Explosives, 27, II
Bureau of
Drug Enforcement Administration 21, II
Federal Acquisition Regulation 48, 28
Federal Claims Collection Standards 31, IX
Federal Prison Industries, Inc. 28, III
Foreign Claims Settlement Commission of the 45, V
United States
Immigration Review, Executive Office for 8, V
Independent Counsel, Offices of 28, VI
Prisons, Bureau of 28, V
Property Management Regulations 41, 128
Labor, Department of 2, XXIX; 5, XLII
Employee Benefits Security Administration 29, XXV
Employees' Compensation Appeals Board 20, IV
Employment and Training Administration 20, V
Employment Standards Administration 20, VI
Federal Acquisition Regulation 48, 29

[[Page 661]]

Federal Contract Compliance Programs, Office 41, 60
of
Federal Procurement Regulations System 41, 50
Labor-Management Standards, Office of 29, II, IV
Mine Safety and Health Administration 30, I
Occupational Safety and Health Administration 29, XVII
Public Contracts 41, 50
Secretary of Labor, Office of 29, Subtitle A
Veterans' Employment and Training Service, 41, 61; 20, IX
Office of the Assistant Secretary for
Wage and Hour Division 29, V
Workers' Compensation Programs, Office of 20, I, VII
Labor-Management Standards, Office of 29, II, IV
Land Management, Bureau of 43, II
Legal Services Corporation 45, XVI
Libraries and Information Science, National 45, XVII
Commission on
Library of Congress 36, VII
Copyright Royalty Board 37, III
U.S. Copyright Office 37, II
Local Television Loan Guarantee Board 7, XX
Management and Budget, Office of 5, III, LXXVII; 14, VI;
48, 99
Marine Mammal Commission 50, V
Maritime Administration 46, II
Merit Systems Protection Board 5, II, LXIV
Micronesian Status Negotiations, Office for 32, XXVII
Military Compensation and Retirement 5, XCIX
Modernization Commission
Millennium Challenge Corporation 22, XIII
Mine Safety and Health Administration 30, I
Minority Business Development Agency 15, XIV
Miscellaneous Agencies 1, IV
Monetary Offices 31, I
Morris K. Udall Scholarship and Excellence in 36, XVI
National Environmental Policy Foundation
Museum and Library Services, Institute of 2, XXXI
National Aeronautics and Space Administration 2, XVIII; 5, LIX; 14, V
Federal Acquisition Regulation 48, 18
National Agricultural Library 7, XLI
National Agricultural Statistics Service 7, XXXVI
National and Community Service, Corporation for 2, XXII; 45, XII, XXV
National Archives and Records Administration 2, XXVI; 5, LXVI; 36, XII
Information Security Oversight Office 32, XX
National Capital Planning Commission 1, IV, VI
National Counterintelligence Center 32, XVIII
National Credit Union Administration 5, LXXXVI; 12, VII
National Crime Prevention and Privacy Compact 28, IX
Council
National Drug Control Policy, Office of 2, XXXVI; 21, III
National Endowment for the Arts 2, XXXII
National Endowment for the Humanities 2, XXXIII
National Foundation on the Arts and the 45, XI
Humanities
National Geospatial-Intelligence Agency 32, I
National Highway Traffic Safety Administration 23, II, III; 47, VI; 49, V
National Imagery and Mapping Agency 32, I
National Indian Gaming Commission 25, III
National Institute of Food and Agriculture 7, XXXIV
National Institute of Standards and Technology 15, II; 37, IV
National Intelligence, Office of Director of 5, IV; 32, XVII
National Labor Relations Board 5, LXI; 29, I
National Marine Fisheries Service 50, II, IV
National Mediation Board 29, X
National Oceanic and Atmospheric Administration 15, IX; 50, II, III, IV,
VI
National Park Service 36, I
National Railroad Adjustment Board 29, III
National Railroad Passenger Corporation (AMTRAK) 49, VII
National Science Foundation 2, XXV; 5, XLIII; 45, VI
Federal Acquisition Regulation 48, 25

[[Page 662]]

National Security Council 32, XXI
National Security Council and Office of Science 47, II
and Technology Policy
National Telecommunications and Information 15, XXIII; 47, III, IV, V
Administration
National Transportation Safety Board 49, VIII
Natural Resources Conservation Service 7, VI
Natural Resource Revenue, Office of 30, XII
Navajo and Hopi Indian Relocation, Office of 25, IV
Navy, Department of 32, VI
Federal Acquisition Regulation 48, 52
Neighborhood Reinvestment Corporation 24, XXV
Northeast Interstate Low-Level Radioactive Waste 10, XVIII
Commission
Nuclear Regulatory Commission 2, XX; 5, XLVIII; 10, I
Federal Acquisition Regulation 48, 20
Occupational Safety and Health Administration 29, XVII
Occupational Safety and Health Review Commission 29, XX
Ocean Energy Management, Bureau of 30, V
Oklahoma City National Memorial Trust 36, XV
Operations Office 7, XXVIII
Overseas Private Investment Corporation 5, XXXIII; 22, VII
Patent and Trademark Office, United States 37, I
Payment From a Non-Federal Source for Travel 41, 304
Expenses
Payment of Expenses Connected With the Death of 41, 303
Certain Employees
Peace Corps 2, XXXVII; 22, III
Pennsylvania Avenue Development Corporation 36, IX
Pension Benefit Guaranty Corporation 29, XL
Personnel Management, Office of 5, I, XXXV; 5, IV; 45,
VIII
Human Resources Management and Labor Relations 5, XCVII
Systems, Department of Homeland Security
Federal Acquisition Regulation 48, 17
Federal Employees Group Life Insurance Federal 48, 21
Acquisition Regulation
Federal Employees Health Benefits Acquisition 48, 16
Regulation
Pipeline and Hazardous Materials Safety 49, I
Administration
Postal Regulatory Commission 5, XLVI; 39, III
Postal Service, United States 5, LX; 39, I
Postsecondary Education, Office of 34, VI
President's Commission on White House 1, IV
Fellowships
Presidential Documents 3
Presidio Trust 36, X
Prisons, Bureau of 28, V
Privacy and Civil Liberties Oversight Board 6, X
Procurement and Property Management, Office of 7, XXXII
Public Contracts, Department of Labor 41, 50
Public and Indian Housing, Office of Assistant 24, IX
Secretary for
Public Health Service 42, I
Railroad Retirement Board 20, II
Reclamation, Bureau of 43, I
Refugee Resettlement, Office of 45, IV
Relocation Allowances 41, 302
Research and Innovative Technology 49, XI
Administration
Rural Business-Cooperative Service 7, XVIII, XLII
Rural Development Administration 7, XLII
Rural Housing Service 7, XVIII, XXXV
Rural Telephone Bank 7, XVI
Rural Utilities Service 7, XVII, XVIII, XLII
Safety and Environmental Enforcement, Bureau of 30, II
Saint Lawrence Seaway Development Corporation 33, IV
Science and Technology Policy, Office of 32, XXIV
Science and Technology Policy, Office of, and 47, II
National Security Council
Secret Service 31, IV
Securities and Exchange Commission 5, XXXIV; 17, II

[[Page 663]]

Selective Service System 32, XVI
Small Business Administration 2, XXVII; 13, I
Smithsonian Institution 36, V
Social Security Administration 2, XXIII; 20, III; 48, 23
Soldiers' and Airmen's Home, United States 5, XI
Special Counsel, Office of 5, VIII
Special Education and Rehabilitative Services, 34, III
Office of
State, Department of 2, VI; 22, I; 28, XI
Federal Acquisition Regulation 48, 6
Surface Mining Reclamation and Enforcement, 30, VII
Office of
Surface Transportation Board 49, X
Susquehanna River Basin Commission 18, VIII
Tennessee Valley Authority 5, LXIX; 18, XIII
Thrift Supervision Office, Department of the 12, V
Treasury
Trade Representative, United States, Office of 15, XX
Transportation, Department of 2, XII; 5, L
Commercial Space Transportation 14, III
Emergency Management and Assistance 44, IV
Federal Acquisition Regulation 48, 12
Federal Aviation Administration 14, I
Federal Highway Administration 23, I, II
Federal Motor Carrier Safety Administration 49, III
Federal Railroad Administration 49, II
Federal Transit Administration 49, VI
Maritime Administration 46, II
National Highway Traffic Safety Administration 23, II, III; 47, IV; 49, V
Pipeline and Hazardous Materials Safety 49, I
Administration
Saint Lawrence Seaway Development Corporation 33, IV
Secretary of Transportation, Office of 14, II; 49, Subtitle A
Transportation Statistics Bureau 49, XI
Transportation, Office of 7, XXXIII
Transportation Security Administration 49, XII
Transportation Statistics Bureau 49, XI
Travel Allowances, Temporary Duty (TDY) 41, 301
Treasury, Department of 2, X;5, XXI; 12, XV; 17,
IV; 31, IX
Alcohol and Tobacco Tax and Trade Bureau 27, I
Community Development Financial Institutions 12, XVIII
Fund
Comptroller of the Currency 12, I
Customs and Border Protection 19, I
Engraving and Printing, Bureau of 31, VI
Federal Acquisition Regulation 48, 10
Federal Claims Collection Standards 31, IX
Federal Law Enforcement Training Center 31, VII
Financial Crimes Enforcement Network 31, X
Fiscal Service 31, II
Foreign Assets Control, Office of 31, V
Internal Revenue Service 26, I
Investment Security, Office of 31, VIII
Monetary Offices 31, I
Secret Service 31, IV
Secretary of the Treasury, Office of 31, Subtitle A
Thrift Supervision, Office of 12, V
Truman, Harry S. Scholarship Foundation 45, XVIII
United States and Canada, International Joint 22, IV
Commission
United States and Mexico, International Boundary 22, XI
and Water Commission, United States Section
U.S. Copyright Office 37, II
Utah Reclamation Mitigation and Conservation 43, III
Commission
Veterans Affairs, Department of 2, VIII; 38, I
Federal Acquisition Regulation 48, 8
Veterans' Employment and Training Service, 41, 61; 20, IX
Office of the Assistant Secretary for
Vice President of the United States, Office of 32, XXVIII
Wage and Hour Division 29, V
Water Resources Council 18, VI
Workers' Compensation Programs, Office of 20, I, VII

[[Page 664]]

World Agricultural Outlook Board 7, XXXVIII

[[Page 665]]

List of CFR Sections Affected

All changes in this volume of the Code of Federal Regulations (CFR) that
were made by documents published in the Federal Register since January
1, 2013 are enumerated in the following list. Entries indicate the
nature of the changes effected. Page numbers refer to Federal Register
pages. The user should consult the entries for chapters, parts and
subparts as well as sections for revisions.
For changes to this volume of the CFR prior to this listing, consult the
annual edition of the monthly List of CFR Sections Affected (LSA). The
LSA is available at www.fdsys.gov. For changes to this volume of the CFR
prior to 2001, see the ``List of CFR Sections Affected, 1949-1963, 1964-
1972, 1973-1985, and 1986-2000'' published in 11 separate volumes. The
``List of CFR Sections Affected 1986-2000'' is available at
www.fdsys.gov.

2013

30 CFR
78 FR
Page
Chapter II
201.350 Correctly redesignated as 1202.350.........................30201
218.153 Correctly redesignated as 1218.153.........................30207
250.105 Amended....................................................20439
250.125 (a) table revised..........................................60213
250.193 Revised....................................................20439
250.198 (m) and (n) added..........................................20440
250.1900 (a) and (b) removed; (c) and (d) redesignated as (a) and
(b); new (a) revised.......................................20440
250.1901 (a) revised...............................................20440
250.1902 (a)(12), (13) and (b) revised; (a)(14) through (17) added
20440
250.1903 Revised...................................................20440
250.1904 Revised...................................................20441
250.1911 Heading, introductory text, (a) introductory text and (b)
revised; (a)(4) and (c) added..............................20441
250.1914 Introductory text and (a) revised.........................20441
250.1915 Heading, introductory text, (c) and (d) revised...........20441
250.1920 (a), (b)(5), (6), (c) and (d) revised; (e) removed........20442
250.1921 Added.....................................................20442
250.1922 Added.....................................................20442
250.1924 (a) and (b)(2) revised; (d) removed.......................20442
250.1925 Revised...................................................20442
250.1926 Removed...................................................20442
250.1928 (b) revised; (f) redesignated as (h); new (f) and (g)
added......................................................20442
250.1930 Added.....................................................20443
250.1931 Added.....................................................20443
250.1932 Added.....................................................20443
250.1933 Added.....................................................20443

2014

30 CFR
79 FR
Page
Chapter V
553 Authority citation revised.....................................73839
553.1 Revised......................................................73839
553.3 Amended......................................................73839
553.700--553.704 (Subpart G) Added.................................73840
585.102 (e) revised................................................21621
585.112 Amended....................................................21621
585.203 Revised....................................................21621
585.211 (c) revised................................................21621
585.212 (a) revised................................................21621
585.224 (b) revised................................................21621
585.231 (d), (e), (f) and (g)(2) revised...........................21622
585.235 (a) revised................................................21622
585.236 (a) revised................................................21622
585.303 Revised....................................................21623
585.306 (b) revised; (c) removed...................................21623
585.309 Introductory text revised..................................21623
585.500 (a) and (b) revised........................................21623

[[Page 666]]

585.503 (a)(1) revised.............................................21623
585.505 (b) revised................................................21623
585.601 Introductory text and (a) revised; (b) removed; (c) and
(d) redesignated as new (b) and (c)........................21623
585.611 Revised....................................................21623
585.612 Revised....................................................21624
585.627 (a) and (b) revised........................................21624
585.628 (c) revised................................................21625
585.640 (b) revised................................................21625
585.646 Revised....................................................21625
585.647 Revised....................................................21625
590 Authority citation revised.....................................21626
590.4 (b)(1) revised...............................................21626

2015

30 CFR
80 FR
Page
Chapter II
250.1704 Heading and introductory text revised; table amended......75810
Chapter V
519 Authority citation revised.....................................57096
Removed........................................................81458
519.410 (b) amended................................................57096
550 Authority citation revised.....................................57096
550.126 Introductory text amended..................................57096
550.199 (d) revised................................................57096
550.1153 (d) amended...............................................57096
550.1454 Amended...................................................57096
550.1456 (b) revised...............................................57096
550.1462 Amended...................................................57096
550.1464 (b) revised...............................................57096
550.1495 (a)(1), (2) and (3) revised...............................57096
551 Authority citation revised.....................................57096
551.5 (d)(1) and (3) revised.......................................57096
551.7 (d)(4) revised...............................................57097
551.15 (e) revised.................................................57097
553 Authority citation revised.....................................57097
553.5 (d) revised..................................................57097
556 Authority citation revised.....................................57097
556.0 (d) revised..................................................57097
556.54 (b) and (f) revised.........................................57097
560 Authority citation revised.....................................57097
560.3 (b) revised..................................................57097
580 Authority citation revised.....................................57097
580.13 (b) and (c) revised.........................................57097
580.80 (e) revised.................................................57098
581 Authority citation revised.....................................57098
581.33 (b) amended.................................................57098
582 Authority citation revised.....................................57098
582.40 (b) amended.................................................57098
585 Authority citation revised.....................................57098
585.110 (a) revised................................................57098
585.114 (d) revised................................................57098
585.115 (d) amended................................................57098

2016

30 CFR
81 FR
Page
Chapter II
203 Nomenclature change; eff. 7-28-16..............................36148
203.3 (b) revised; eff. 7-28-16....................................36148
203.5 (a) amended; eff. 7-28-16....................................36148
250 Authority citation revised..............................36148, 46560
Nomenclature change; eff. 7-28-16..............................36148
250.102 (b)(1), (11), (12) and (13) revised; (b)(19) added; eff.
7-28-16....................................................26013
(b) table revised; eff. 7-28-16................................36148
250.105 Amended....................................................46560
250.107 (a)(1) and (2) amended; (a)(3), (4) and (e) added; eff. 7-
28-16......................................................26014
(c) revised; (d) removed; (e) redesignated as new (d)..........61915
250.114 (a) amended; eff. 7-28-16..................................36149
Heading revised................................................61916
250.118 Undesignated center heading added; eff. 7-28-16............36149
250.125 (a) table revised; eff. 7-28-16............................26014
(a) table revised..............................................61916
250.126 Revised; eff. 7-28-16......................................36149
250.188 (c) added..................................................46560
250.193 (e)(2)(i)(C) amended; eff. 7-28-16.........................36149
250.198 (h)(51), (63), (68) and (70) revised; (h)(88) amended;
(h)(89) through (94) added; eff. 7-28-16...................26015
(d), (e) introductory text, (g) introductory text, (i)
introductory text, (j) introductory text, (k) introductory text
and (m) introductory text revised; eff. 7-28-16....................36149
(h)(95) added..................................................46560

[[Page 667]]

(g)(1), (2), (3), (h)(1), (51), (52), (53), (55) through (62),
(65), (66), (68), (70), (71), (73), (74), (93), (94) and (95)
revised; (g)(6) and (7) removed; (g)(8) redesignated as new
(g)(6); (h)(96) added..............................................61917
250.199 (e) revised; eff. 7-28-16..................................26015
250.292 (o) amended; (p) redesignated as (q); new (p) added; eff.
7-28-16....................................................26017
250.300 (b)(1) and (2) revised.....................................46560
250.400 Revised; eff. 7-28-16......................................26017
250.401 Removed; eff. 7-28-16......................................26017
250.402 Removed; eff. 7-28-16......................................26017
250.403 Removed; eff. 7-28-16......................................26017
250.405 Introductory text amended; eff. 7-28-16....................36149
250.406 Removed; eff. 7-28-16......................................26017
250.411 Revised; eff. 7-28-16......................................26017
250.413 (g) revised; eff. 7-28-16..................................26017
250.414 (c), (h) and (i) revised; (j) and (k) added; eff. 7-28-16
26017
250.415 (a) revised; eff. 7-28-16..................................26018
250.416 Revised; eff. 7-28-16......................................26018
250.417 Removed; eff. 7-28-16......................................26018
250.418 (g) and (h) revised; (i) removed; (j) redesignated as new
(i); eff. 7-28-16..........................................26018
(j) added......................................................46561
250.420 Introductory text, (a)(5) and (c) revised; (a)(6)
redesignated as (a)(7); new (a)(6) and (b)(4) added; eff.
7-28-16....................................................26018
250.421 (b) and (f) revised; eff. 7-28-16..........................26018
250.423 Revised; eff. 7-28-16......................................26019
250.424 Removed; eff. 7-28-16......................................26019
250.425 Removed; eff. 7-28-16......................................26019
250.426 Removed; eff. 7-28-16......................................26019
250.427 (b) revised; eff. 7-28-16..................................26019
250.428 (b), (c) and (d) revised; (k) added; eff. 7-28-16..........26019
250.440 Removed; eff. 7-28-16......................................26020
250.441 Removed; eff. 7-28-16......................................26020
250.442 Removed; eff. 7-28-16......................................26020
250.443 Removed; eff. 7-28-16......................................26020
250.444 Removed; eff. 7-28-16......................................26020
250.445 Removed; eff. 7-28-16......................................26020
250.446 Removed; eff. 7-28-16......................................26020
250.447 Removed; eff. 7-28-16......................................26020
250.448 Removed; eff. 7-28-16......................................26020
250.449 Removed; eff. 7-28-16......................................26020
250.450 Removed; eff. 7-28-16......................................26020
250.451 Removed; eff. 7-28-16......................................26020
250.452 Added......................................................46561
250.456 (i) amended; (j) removed; (k) redesignated as new (j);
eff. 7-28-16...............................................26020
250.462 Revised; eff. 7-28-16......................................26020
250.465 (b)(3) revised; eff. 7-28-16...............................26021
250.466 Removed; eff. 7-28-16......................................26021
250.467 Removed; eff. 7-28-16......................................26021
250.468 Removed; eff. 7-28-16......................................26021
250.469 Removed; eff. 7-28-16......................................26021
250.470 Undesignated center heading and section added..............46561
250.471 Added......................................................46561
250.472 Added......................................................46561
250.473 Added......................................................46561
250.500 Revised; eff. 7-28-16......................................26021
250.502 Removed; eff. 7-28-16......................................26021
250.506 Removed; eff. 7-28-16......................................26021
250.513 (b)(4) revised; eff. 7-28-16...............................26021
250.514 (d) removed; eff. 7-28-16..................................26021
250.515 Removed; eff. 7-28-16......................................26021
250.516 Removed; eff. 7-28-16......................................26021
250.517 Removed; eff. 7-28-16......................................26021
250.518 (b) removed; (c), (d) and (e) redesignated as new (b), (c)
and (d); new (e) and (f) added; eff. 7-28-16...............26021
250.518 (d) revised................................................61918
250.600 Revised; eff. 7-28-16......................................26021
250.602 Removed; eff. 7-28-16......................................26021
250.606 Removed; eff. 7-28-16......................................26021
250.610 Revised; eff. 7-28-16......................................36149
250.611 Revised; eff.7-28-16.......................................36149
250.613 (b)(3) revised; eff. 7-28-16...............................26021
250.614 (d) removed; eff. 7-28-16..................................26021
250.615 Removed; eff. 7-28-16......................................26021
250.616 Heading revised; (a) through (e) removed; (f), (g) and (h)
redesignated as new (a), (b) and (c); eff. 7-28-16.........26021
250.617 Removed; eff. 7-28-16......................................26021
250.618 Removed; eff. 7-28-16......................................26021
250.619 (b) removed; (c), (d) and (e) redesignated as new (b), (c)
and (d); new (e) and (f) added; eff. 7-28-16...............26021
(d) revised....................................................61918
250.700--250.746 (Subpart G) Added; eff. 7-28-16...................26022
250.713 (b) amended; eff. 7-28-16..................................36150
250.720 (c) added..................................................46563
250.800--250.899 (Subpart H) Revised...............................61918

[[Page 668]]

250.803 (b)(1) introductory text amended; eff. 7-28-16.............36150
250.806 (c) amended; eff. 7-28-16..................................36150
250.901 (a)(24) amended; eff. 7-28-16..............................36150
250.904 (b) amended; eff. 7-28-16..................................36150
Regulation at 81 FR 36150 withdrawn............................40812
250.908 (a) table amended; eff. 7-28-16............................36150
250.920 (b) amended; eff. 7-28-16..................................36150
250.1000 (c)(3)(i), (iv), (4), (12)(ii), (13)(i) and (ii) revised;
eff. 7-28-16...............................................36150
250.1015 (e) removed; eff. 7-28-16.................................36150
250.1018 (c) removed; eff. 7-28-16.................................36150
250.1165 (b) amended; eff. 7-28-16.................................36150
250.1302 (a) amended; (c) and (d) revised; eff. 7-28-16............36150
250.1401 Removed; eff. 7-28-16.....................................36150
250.1403 Revised; interim; eff. 7-28-16............................41803
Regulation at 81 FR 41803 confirmed............................80996
250.1455 (b)(2) revised; eff. 7-28-16..............................36150
250.1463 (b)(2) revised; eff. 7-28-16..............................36150
250.1490 Undesignated center heading and section removed; eff. 7-
28-16......................................................36151
250.1491 Removed; eff. 7-28-16.....................................36151
250.1495 Undesignated center heading and section removed; eff. 7-
28-16......................................................36151
250.1496 Removed; eff. 7-28-16.....................................36151
250.1497 Removed; eff. 7-28-16.....................................36151
250.1609 (b) amended; eff. 7-28-16.................................36151
250.1612 Revised; eff. 7-28-16.....................................26037
250.1703 (b) and (e) revised; (f) redesignated as (g); new (f)
added; eff. 7-28-16........................................26037
250.1704 (g) revised; (h) and (i) redesignated as (i) and (j); new
(h) added; eff. 7-28-16....................................26037
Table amended..................................................80591
250.1705 Removed; eff. 7-28-16.....................................26037
250.1706 Heading revised; (a) through (e) removed; (f), (g) and
(h) redesignated as new (a), (b) and (c); eff. 7-28-16.....26037
250.1707 Removed; eff. 7-28-16.....................................26038
250.1708 Removed; eff. 7-28-16.....................................26038
250.1709 Removed; eff. 7-28-16.....................................26038
250.1715 (a)(3)(iii)(B) revised; eff. 7-28-16......................26038
250.1717 Removed; eff. 7-28-16.....................................26038
250.1721 (g) removed; (h) redesignated as new (g); eff. 7-28-16....26038
250.1920 (b)(5) revised; (e) added; eff. 7-28-16...................36151
(b)(5), (c) and (d) amended; (f) and (g) added.................46563
251.15 Revised; eff. 7-28-16.......................................36151
252.2 Amended; eff. 7-28-16........................................36151
254.1 Heading, (a), (b), (d) and (e) revised; eff. 7-28-16.........36151
254.2 Revised; eff. 7-28-16........................................36151
254.3 Revised; eff. 7-28-16........................................36151
254.4 Revised; eff. 7-28-16........................................36152
254.5 (a), (b) and (d) revised; eff. 7-28-16.......................36152
254.6 Amended; eff. 7-28-16........................................36152
Amended........................................................46563
254.7 Revised; eff. eff. 7-28-16...................................36152
254.9 (a) amended; eff. 7-28-16....................................36152
254.20 Amended; eff. 7-28-16.......................................36152
254.21 Heading, (a), (b) introductory text and (1) revised; eff.
7-28-16....................................................36152
254.22 Heading, introductory text, (a), (c) and (d) amended; eff.
7-28-16....................................................36152
254.23 Introductory text amended; eff. 7-28-16.....................36152
254.25 Amended; eff. 7-28-16.......................................36152
254.30 Revised; eff. 7-28-16.......................................36152
254.41 (d) amended; eff. 7-28-16...................................36153
254.42 (a), (b)(2) and (e) revised; (f), (h) and (i) amended; eff.
7-28-16....................................................36153
254.43 (a) amended; eff. 7-28-16...................................36153
254.44 (a) amended; eff. 7-28-16...................................36153
254.45 (a) amended; eff. 7-28-16...................................36153
254.46 (b)(2) amended; eff. 7-28-16................................36153
254.47 (d) amended; eff. 7-28-16...................................36153
254.51 Heading amended; eff. 7-28-16...............................36153
254.52 Heading amended; eff. 7-28-16...............................36153

[[Page 669]]

254.53 Heading and (a) introductory text amended; eff. 7-28-16.....36153
254.54 Amended; eff. 7-28-16.......................................36153
254.55 Added.......................................................46563
254.65--254.90 (Subpart E) Added...................................46564
256.0 Removed; eff. 7-28-16........................................36153
256.2 Removed; eff. 7-28-16........................................36153
256.3 Removed; eff. 7-28-16........................................36153
256.4 Removed; eff. 7-28-16........................................36153
256.5 Removed; eff. 7-28-16........................................36153
256.7 (j) added; eff. 7-28-16......................................36153
256.8 Removed; eff. 7-28-16........................................36153
256.9 Removed; eff. 7-28-16........................................36153
256.10 Removed; eff. 7-28-16.......................................36153
256.11 Removed; eff. 7-28-16.......................................36153
256.12 Removed; eff. 7-28-16.......................................36153
256.8 Removed; eff. 7-28-16........................................36153
256 Subparts B through I removed; eff. 7-28-16.....................36153
256.62--256.73 (Subpart B) Redesignated from Subpart J; eff. 7-28-
16.........................................................36153
256.62--256.73 (Subpart J) Redesignated as Subpart B; eff. 7-28-16
36153
256.62 Removed; eff. 7-28-16.......................................36153
256.63 Removed; eff. 7-28-16.......................................36153
256.64 Removed; eff. 7-28-16.......................................36153
256.65 Removed; eff. 7-28-16.......................................36153
256.66 Removed; eff. 7-28-16.......................................36153
256.67 Removed; eff. 7-28-16.......................................36153
256.68 Removed; eff. 7-28-16.......................................36153
256.76--256.77 (Subpart C) Redesignated from Subpart K; eff. 7-28-
16.........................................................36153
256.76--256.77 (Subpart K) Redesignated as Subpart C; eff. 7-28-16
36153
256.76 Removed; eff. 7-28-16.......................................36153
256.79--256.80 (Subpart D) Redesignated from Subpart L; eff. 7-28-
16.........................................................36153
256.79--256.80 (Subpart L) Redesignated as Subpart D; eff. 7-28-16
36153
256.80 Removed; eff. 7-28-16.......................................36153
256 Subparts M and N removed; eff. 7-28-16.........................36153
280.25 (a)(2) amended; eff. 7-28-16................................36153
280.28 (a) amended; eff. 7-28-16...................................36153
282.0 Existing text designated as (a) and amended; (b) added; eff.
7-28-16....................................................36153
282.3 Amended; eff. 7-28-16........................................36153
282.13 (d) and (e)(2) revised; eff. 7-28-16........................36153
282.14 (c) amended; eff. 7-28-16...................................36154
282.27 (d)(2) revised; eff. 7-28-16................................36154
290 Authority citation revised.....................................36154
290.4 (b)(1) revised; eff. 7-28-16.................................36154
291.1 (a) and (e) amended; eff. 7-28-16............................36154
291.103 Introductory text amended; eff. 7-28-16....................36154
291.106 (a) amended; eff. 7-28-16..................................36154
291.107 (a) and (b)(1) amended; eff. 7-28-16.......................36154
291.108 (a) revised; eff. 7-28-16..................................36154
291.109 (a)(1) and (b) amended; eff. 7-28-16.......................36154
Chapter V
550 Authority citation revised.......................18152, 43069, 46564
Policy statement...............................................46599
550.105 Amended....................................................46565
550.120 Added......................................................18152
550.121 Added......................................................18152
550.145 Redesignated as 550.146....................................18152
550.146 Redesignated as 550.147; redesignated from 550.145.........18152
550.147 Redesignated from 550.146..................................18152
550.197 Introductory text amended; (b)(5) and (c) revised; (d)
added......................................................18152
550.200 (a) amended................................................46565
550.204 Added......................................................46565
550.206 Revised....................................................46565
550.220 (a) revised; (c) added.....................................46565
550.400 (Subpart D) Added..........................................18152
550.1403 Revised; interim; eff. 8-1-16.............................43069
553 Authority citation revised.....................................43069
553.51 (a) revised; interim; eff. 8-1-16...........................43069
556 Revised........................................................18152
Policy statement...............................................46599
556.105 Amended....................................................70358
556.403 Correctly revised..........................................34275
559 Removed........................................................18174
560.1 Redesignated as 560.101......................................18175
560.2 Redesignated as 560.102......................................18175
560.3 Redesignated as 560.103......................................18175
560.100 Added......................................................18175
560.101 Redesignated as 560.200; redesignated from 560.1...........18175

[[Page 670]]

560.102 Redesignated as 560.201; redesignated from 560.2 and
revised....................................................18175
560.103 Redesignated from 560.3....................................18175
560.110 Redesignated as 560.202....................................18175
560.111 Redesignated as 560.203....................................18175
560.112 Redesignated as 560.210....................................18175
560.113 Redesignated as 560.211....................................18175
560.114 Redesignated as 560.212....................................18175
560.115 Redesignated as 560.213....................................18175
560.116 Redesignated as 560.214....................................18175
560.120 Redesignated as 560.220....................................18175
560.121 Redesignated as 560.221....................................18175
560.122 Redesignated as 560.222....................................18175
560.123 Redesignated as 560.223....................................18175
560.124 Redesignated as 560.224....................................18175
560.130 Redesignated as 560.230....................................18175
560.200 Redesignated from 560.101..................................18175
560.201 Redesignated from 560.102..................................18175
560.202 Redesignated from 560.110..................................18175
560.203 Redesignated from 560.111..................................18175
560.210 Redesignated from 560.112..................................18175
560.211 Redesignated from 560.113..................................18175
560.212 Redesignated from 560.114..................................18175
560.213 Redesignated from 560.115..................................18175
560.214 Redesignated from 560.116..................................18175
560.220 Redesignated from 560.120..................................18175
560.221 Redesignated from 560.121..................................18175
560.222 Redesignated from 560.122..................................18175
560.223 Redesignated from 560.123..................................18175
560.224 Redesignated from 560.124..................................18175
560.230 Redesignated from 560.130..................................18175
560.300 (Subpart C) Added..........................................18175
560.301--560.302 (Subpart D) Removed...............................18176
560.500--560.502 (Subpart E) Added.................................18176

2017

30 CFR
82 FR
Page
Chapter II
Chapter II Policy statement........................................50532
250.171 Introductory text revised..................................26744
250.180 (a)(1), (b), (d), (e), (g) and (j) revised.................26744
250.1403 Revised....................................................9138
Chapter IV
Chapter IV Policy statement........................................50532
Chapter V
Chapter V Policy statement.........................................50532
550.1403 Revised...................................................10711
553.51 (a) revised.................................................10711
583 Added..........................................................45973

2018

(Regulations published from January 1, 2018, through July 1, 2018)

30 CFR
83 FR
Page
Chapter II
250.1403 Revised....................................................2540
Chapter V
550.1403 Revised....................................................8933
553.51 (a) revised..................................................8933
553.702 Revised.....................................................2542

[all]