[Title 30 CFR ]
[Code of Federal Regulations (annual edition) - July 1, 2011 Edition]
[From the U.S. Government Printing Office]
[[Page 1]]
Title 30
Mineral Resources
________________________
Parts 200 to 699
Revised as of July 1, 2011
Containing a codification of documents of general
applicability and future effect
As of July 1, 2011
Published by the Office of the Federal Register
National Archives and Records Administration as a
Special Edition of the Federal Register
[[Page ii]]
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[[Page iii]]
Table of Contents
Page
Explanation................................................. v
Title 30:
Chapter II--Bureau of Ocean Energy Management,
Regulation, and Enforcement, Department of the
Interior 3
Chapter IV--Geological Survey, Department of the
Interior 515
Finding Aids:
Table of CFR Titles and Chapters........................ 529
Alphabetical List of Agencies Appearing in the CFR...... 549
List of CFR Sections Affected........................... 559
[[Page iv]]
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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.
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[[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
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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
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collection request.
[[Page vi]]
Many agencies have begun publishing numerous OMB control numbers as
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[[Page vii]]
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Office of the Federal Register.
July 1, 2011.
[[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, 2011.
For this volume, Cheryl E. Sirofchuck was Chief Editor. The Code of
Federal Regulations publication program is under the direction of
Michael L. White, assisted by Ann Worley.
[[Page 1]]
TITLE 30--MINERAL RESOURCES
(This book contains parts 200 to 699)
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Part
chapter ii--Bureau of Ocean Energy Management, Regulation,
and Enforcement, Department of the Interior............... 203
chapter iv--Geological Survey, Department of the Interior... 401
[[Page 3]]
CHAPTER II--BUREAU OF OCEAN ENERGY MANAGEMENT, REGULATION, AND
ENFORCEMENT, DEPARTMENT OF THE INTERIOR
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SUBCHAPTER A--MINERALS REVENUE MANAGEMENT
Part Page
203 Relief or reduction in royalty rates........ 5
219 Distribution and disbursement of royalties,
rentals, and bonuses.................... 44
SUBCHAPTER B--OFFSHORE
250 Oil and gas and sulphur operations in the
Outer Continental Shelf................. 49
251 Geological and geophysical (G&G)
explorations of the Outer Continental
Shelf................................... 281
252 Outer Continental Shelf (OCS) oil and gas
information program..................... 295
253 Oil spill financial responsibility for
offshore facilities..................... 301
254 Oil-spill response requirements for
facilities located seaward of the coast
line.................................... 314
256 Leasing of sulphur or oil and gas in the
Outer Continental Shelf................. 327
259 Mineral leasing: Definitions................ 357
260 Outer Continental Shelf oil and gas leasing. 357
270 Nondiscrimination in the Outer Continental
Shelf................................... 364
280 Prospecting for minerals other than oil,
gas, and sulphur on the Outer
Continental Shelf....................... 365
281 Leasing of minerals other than oil, gas, and
sulphur in the Outer Continental Shelf.. 377
282 Operations in the Outer Continental Shelf
for minerals other than oil, gas, and
sulphur................................. 390
285 Renewable energy alternate uses of existing
facilities on the Outer Continental
Shelf................................... 412
SUBCHAPTER C--APPEALS
290 Appeals procedures.......................... 508
[[Page 4]]
291 Open and nondiscriminatory access to oil and
gas pipelines under the Outer
Continental Shelf Lands Act............. 509
[[Page 5]]
SUBCHAPTER A_MINERALS REVENUE MANAGEMENT
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 MMS'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 MMS'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 Sec. 203.0
and Sec. Sec. 203.40 through 203.47 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 MMS 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 MMS take to evaluate my application?
203.66 What happens if MMS 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 MMS consider in determining
economic viability?
203.69 If my application is approved, what royalty relief will I
receive?
[[Page 6]]
203.70 What information must I provide after MMS approves relief?
203.71 How does MMS 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 MMS reconsider its determination?
203.75 What risk do I run if I request a redetermination?
203.76 When might MMS 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 MMS under Sec. Sec. 203.60-203.77
for my lease, unit or project if prices rise significantly?
203.79 How do I appeal MMS'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 MMS'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.
Subpart A_General Provisions
Source: 63 FR 2616, Jan. 16, 1998, unless otherwise noted.
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 250,
subpart A, and does not produce gas or oil, or meets those producibility
requirements and MMS agrees it is not commercially producible; and
(5) For which you have provided the notices and information required
under Sec. 203.47.
Complete application means an original and two copies of the six
reports consisting of the data specified in 30 CFR 203.81, 203.83 and
203.85 through
[[Page 7]]
203.89, along with one set of digital information, which MMS 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 MMS 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 Development and Production
Plan, a Development Operations Coordination Document (DOCD), or a
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 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
[[Page 8]]
under a DOCD or a Supplement approved by the Secretary of the Interior
after November, 28, 1995.
Nonbinding assessment means an opinion by MMS 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 MMS 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 MMS
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 means 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 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
[[Page 9]]
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 an MMS-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 part 250, subpart A
of this title. Sunk costs include the rig mobilization and material
costs for the discovery well that you incurred before its spud date.
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 part
250, subpart A of
[[Page 10]]
this chapter 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.
[63 FR 2616, Jan. 16, 1998, as amended at 67 FR 1872, Jan. 15, 2002; 69
FR 3509, Jan. 26, 2004; 69 FR 24053, Apr. 30, 2004; 73 FR 69504, Nov.
18, 2008]
Sec. 203.1 What is MMS'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 MMS 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.
[63 FR 2616, Jan. 16, 1998, as amended at 73 FR 69506, Nov. 18, 2008]
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
If you have a lease . . . And if you . . . you . . .
------------------------------------------------------------------------
(a) With earnings that cannot Would abandon A reduced royalty
sustain production (i.e., End- otherwise rate on current
of-life lease). potentially monthly
recoverable production and a
resources but higher royalty
seek to increase rate on
production by additional
operating beyond monthly
the point at production. (See
which the lease Sec. Sec.
is economic under 203.50 through
the existing 203.56.)
royalty rate.
(b) Located in a designated GOM Propose an A royalty
deep water area (i.e., 200 expansion project suspension for a
meters or greater) and acquired and can minimum
in a lease sale held before demonstrate your production volume
November 28, 1995, or after project is plus any
November 28, 2000. uneconomic additional
without royalty production large
relief. enough to make
the project
economic (see
Sec. Sec.
203.60 through
203.79).
[[Page 11]]
(c) Located in a designated GOM Are on a field A royalty
deep water area and acquired in from which no suspension for a
a lease sale held before current pre-Act minimum
November 28, 1995 (Pre-Act lease produced production volume
lease). (other than test plus any
production) additional volume
before November needed to make
28, 1995 the field
(Authorized economic. (See
field). Sec. Sec.
203.60 through
203.79.)
(d) Located in a designated GOM Propose a A royalty
deep water area and acquired in development suspension for a
a lease sale held after project and can minimum
November 28, 2000. demonstrate that production volume
the suspension plus any
volume, if any, additional volume
for your lease is needed to make
not enough to your project
make development economic (see
economic. Sec. Sec.
203.60 through
203.79).
(e) Where royalty relief would Are not eligible A royalty
recover significant additional to apply for end- modification in
resources or, offshore Alaska of-life or deep size, duration,
or in certain areas of the GOM, water royalty or form that
would enable development. relief, but show makes your lease
us you meet or project
certain economic (see
eligibility Sec. 203.80).
conditions.
(f) Located in a designated GOM Drill a deep well A royalty
shallow water area and acquired on a lease that suspension for a
in a lease sale held before is not eligible volume of gas
January 1, 2001, or after for deep water produced from
January 1, 2004, or have royalty relief successful deep
exercised an option to and you have not and ultra-deep
substitute for royalty relief previously wells, or, for
in your lease terms. produced oil or certain
gas from a deep unsuccessful deep
well or an ultra- and ultra-deep
deep well. 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 Drill and produce A royalty
shallow water area. gas from an ultra- suspension for a
deep well on a volume of gas
lease that is not produced from
eligible for deep successful ultra-
water royalty deep and deep
relief and you wells on your
have not lease (see Sec.
previously Sec. 203.30
produced oil or through 203.36).
gas from an ultra-
deep well.
(h) Located in planning areas Propose an A royalty
offshore Alaska. expansion project suspension for a
or propose a minimum
development production volume
project and can plus any
demonstrate that additional volume
the project is needed to make
uneconomic your project
without relief or economic (see
that the Sec. Sec.
suspension 203.60, 203.62,
volume, if any, 203.67 through
for your lease is 203.70, Sec.
not enough to Sec. 203.73 and
make development 203.76 through
economic. 203.79).
------------------------------------------------------------------------
[67 FR 1872, Jan. 15, 2002, as amended at 73 FR 69506, Nov. 18, 2008]
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 MMS 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 Pay.gov
Web site and you must include a copy of the Pay.gov confirmation receipt
page with your application or assessment. The Pay.gov Web site may be
accessed through a link on the MMS Offshore Web site at: http://
www.mms.gov/offshore/ homepage or directly through Pay.gov at: https://
www.pay.gov/paygov/.
[73 FR 49946, Aug. 25, 2008]
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- ------------------------------------------
Information elements life Expansion Pre-act Development
lease 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 and 203.90
through 203.91 to retain royalty relief.
----------------------------------------------------------------------------------------------------------------
Deep water
End-of- ------------------------------------------
Confirmation elements life Expansion Pre-act Development
lease project lease project
----------------------------------------------------------------------------------------------------------------
(1) Fabricator's confirmation report...................... ......... X X X
(2) Post-production development report approved by an ......... X X X
independent certified public accountant (CPA)............
----------------------------------------------------------------------------------------------------------------
(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- ------------------------------------------
Approval conditions life Pre-act Development
lease Expansion lease project
----------------------------------------------------------------------------------------------------------------
(1) At least 12 of the last 15 months have the required X
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% of net X
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 and
203.74 through 203.75 describe, the prerequisites for a redetermination
of our royalty relief decision.
----------------------------------------------------------------------------------------------------------------
Deep water
End-of- ------------------------------------------
Redetermination conditions Life Expansion Pre-act Development
lease project lease project
----------------------------------------------------------------------------------------------------------------
(1) After 12 months under current rate, criteria same as X
for approval.............................................
(2) For material change in geologic data, prices, costs, ......... X X X
or available technology..................................
----------------------------------------------------------------------------------------------------------------
(e) The following table indicates by an X, and Sec. Sec. 203.53 and
203.69 describe, the characteristics of approved royalty relief.
[[Page 13]]
----------------------------------------------------------------------------------------------------------------
Deep water
End-of- ------------------------------------------
Relief rate and volume, subject to certain conditions life Expansion Pre-act Development
lease project lease project
----------------------------------------------------------------------------------------------------------------
(1) One-half pre-application effective lease rate on the X
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 production X
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 the ......... X ......... X
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- ------------------------------------------
Full royalty resumes when life Expansion Pre-act Development
lease project lease project
----------------------------------------------------------------------------------------------------------------
(1) Average NYMEX price for last 12 months is at least 25 X
percent above the average for the qualifying months......
(2) Average NYMEX price for last calendar year exceeds $28/ ......... X X
bbl or $3.50/mcf, escalated by the gross domestic product
(GDP) deflator since 1994................................
(3) Average prices for designated periods exceed levels we ......... X ......... X
specify in the Notice of Sale or the lease...............
----------------------------------------------------------------------------------------------------------------
(g) The following table indicates by an X, and Sec. Sec. 203.55 and
203.76 through 203.77 describe, circumstances under which we end or
reduce royalty relief.
----------------------------------------------------------------------------------------------------------------
Deep water
End-of- ------------------------------------------
Relief withdrawn or reduced life Expansion Pre-act Development
lease 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 that ......... X X X
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 pre- ......... X X X
production costs prior to start of production............
(8) Amount of relief volume is produced................... ......... X X X
----------------------------------------------------------------------------------------------------------------
[67 FR 1873, Jan. 15, 2002, as amended at 69 FR 3509, Jan. 26, 2004]
Sec. 203.5 What is MMS'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 1010-0071. The title of this
information collection is ``30 CFR part 203, Relief or Reduction in
Royalty Rates.''
(b) The MMS 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 a benefit
or are mandatory according to 43 U.S.C. 1331 et
[[Page 14]]
seq. The MMS will protect information considered proprietary under
applicable law and under regulations at 30 CFR 203.63, ``How do I assess
my chances for getting relief?'' and 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, Minerals
Management Service, Mail Stop 5438, 1849 C Street, NW., Washington, DC
20240.
[74 FR 46907, Sept. 14, 2009]
Subpart B_OCS Oil, Gas, and Sulfur General
Source: 63 FR 2618, Jan. 16, 1998, unless otherwise noted.
Royalty Relief for Drilling Ultra-Deep Wells on Leases Not Subject to
Deep Water Royalty Relief
Source: 73 FR 69506, Nov. 18, 2008, unless otherwise noted.
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
qualified phase 3 ultra-deep well Then your lease earns an RSV on
that is: this volume of gas production:
------------------------------------------------------------------------
(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 4 BCF plus 600 MCF times sidetrack
that is a phase 2 ultra-deep well, measured depth (rounded to the
nearest 100 feet) but no more than
25 BCF.
(4) An ultra-deep short sidetrack 0 BCF.
that 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.
[[Page 15]]
(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 following table in BCF or MCF as prescribed in
Sec. 203.33:
------------------------------------------------------------------------
If you have a qualified phase 2 Then your lease earns an RSV on
ultra-deep well that is . . this volume of gas production:
------------------------------------------------------------------------
(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
[[Page 16]]
your lease is part of a unit and Sec. 203.43(a)(2), 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 Sec. 216.53. 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 an MMS-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 an MMS-
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 an MMS-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 MMS 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 MMS 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 MMS 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 MMS 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 MMS deems were
unavoidable.
Sec. 203.36 Do I keep royalty relief if prices rise significantly?
(a) You must pay 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. 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
[[Page 20]]
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 Sec. 218.54 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
Source: 69 FR 3510, Jan. 26, 2004, unless otherwise noted.
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 of this part.
(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.
[73 FR 69510, Nov. 18, 2008]
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.
------------------------------------------------------------------------
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.
[[Page 21]]
(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 qualified phase 1 ultra-deep Then your lease earns an RSV on
well that is: this volume of gas production:
------------------------------------------------------------------------
(1) An original well with a 15 BCF.
perforated 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 sidetrack
interval the top of which is from measured depth (rounded to the
15,000 to less than 18,000 feet nearest 100 feet) but no more than
TVD SS, 15 BCF.
(3) An original well with a 25 BCF.
perforated 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 sidetrack
interval the top of which is at measured depth (rounded to the
least 18,000 feet TVD SS, 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 is . . Then you earn an RSV on this amount of gas production:
.
----------------------------------------------------------------------------------------------------------------
(1) An original well or a sidetrack with a 0 BCF.
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 interval 4 BCF plus 600 MCF times sidetrack measured depth (rounded to the
the top of which is 18,000 feet TVD SS or nearest 100 feet) but no more than 10 BCF.
deeper,
----------------------------------------------------------------------------------------------------------------
(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 depth equals
15.7 BCF because paragraph
[[Page 22]]
(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.
[73 FR 69510, Nov. 18, 2008]
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 your lease cannot earn an RSV
oil from a well with a perforated under Sec. 203.41 as a result
interval the top of which is 18,000 of drilling any subsequent deep
feet TVD SS or deeper, wells or phase 1 ultra-deep
wells.
(b) You determine RSV under Sec. that determination establishes
203.41 for the first qualified deep the total RSV available for that
well or qualified phase 1 ultra-deep drilling depth interval on your
well on your lease (whether an lease (i.e., either 15,000-
original well or a sidetrack) 18,000 feet TVD SS, or 18,000
because you drilled and produced it feet TVD SS and deeper),
within the time intervals set forth regardless of the number of
in the definitions for qualified subsequent qualified wells you
wells, drill to that depth interval.
(c) A qualified deep well or the RSV earned by that well under
qualified phase 1 ultra-deep well on Sec. 203.41 applies only to
your lease is within a unitized production from qualified wells
portion of your lease, on or allocated to your lease
and not to other leases within
the unit.
(d) Your qualified deep well or the lease with the perforated
qualified phase 1 ultra-deep well is interval that initially produces
a directional well (either an earns the RSV. However, if the
original well or a sidetrack) perforated interval crosses a
drilled across a lease line, lease line, the lease where the
surface of the well is located
earns the RSV.
(e) You earn an RSV under Sec. that RSV is in addition to any
203.41, RSS for your lease under Sec.
203.45 that results from a
different wellbore.
(f) Your lease earns an RSV under the RSV is not forfeited or
Sec. 203.41 and later produces terminated, but you may not
from a well that is not a qualified apply the RSV under Sec.
well, 203.41 to production from the
non-qualified well.
(g) You qualify for an RSV under you still owe minimum royalties
paragraphs (b) or (c) of Sec. or rentals in accordance with
203.41, 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.
[73 FR 69512, Nov. 18, 2008]
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 Sec. 216.53, 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
an MMS-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 an MMS-approved unit. Under the unit
[[Page 24]]
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 in Sec. 203.48, you must apply the RSV prescribed under
Sec. 203.41 as required under the following paragraphs (c)(1) through
(c)(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 an MMS-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.
[73 FR 69512, Nov. 18, 2008]
Sec. 203.44 What administrative steps must I take to use the royalty suspension volume?
(a) You must notify the MMS 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:
[[Page 25]]
(1) Provide written notification to the MMS Regional Supervisor for
Production and Development that production has begun; and
(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 MMS 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 MMS 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 MMS deems were
unavoidable.
[69 FR 3510, Jan. 26, 2004, as amended at 69 FR 24054, Apr. 30, 2004.
Redesignated and amended at 73 FR 69512, 69513, Nov. 18, 2008]
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.
204.46.
----------------------------------------------------------------------------------------------------------------
If you have a certified unsuccessful well Then your lease earns an RSS on this volume of oil and gas
that is: production as prescribed in this section and Sec. 203.46:
----------------------------------------------------------------------------------------------------------------
(1) An original well and your lease has not 5 BCFE.
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 sidetrack measured depth (rounded to
depth of at least 10,000 feet) and your the nearest 100 feet) but no more than 5 BCFE.
lease has not produced gas or oil from a
deep well or an ultra-deep well,
(3) An original well or a sidetrack (with a 2 BCFE.
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 Sec. 216.53.
(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
[[Page 26]]
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 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, MMS 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.
[69 FR 3510, Jan. 26, 2004, as amended at 69 FR 24054, Apr. 30, 2004; 72
FR 25198, May 4, 2007; 73 FR 15890, Mar. 26, 2008. Redesignated and
amended at 73 FR 69512, 69513, Nov. 18, 2008; 74 FR 46907, Sept. 14,
2009]
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. 204.47(b),
(2) From, or allocated under an MMS-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
[[Page 27]]
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 an MMS-approved unit
agreement to, your lease.
(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 an MMS-approved unit agreement. If your certified
unsuccessful well is on a lease subject to an MMS-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 an MMS-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.
[69 FR 3510, Jan. 26, 2004. Redesignated and amended at 73 FR 69512,
69514, Nov. 18, 2008]
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
MMS 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 MMS Regional
Supervisor for Production and Development within 60 days after reaching
the total depth in your well:
(1) Information that allows MMS 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 250, subpart A; or
(ii) Well log, well test, seismic, and economic data, if your well
does meet the producibility requirements of 30 CFR part 250, subpart A;
and
(2) Information that allows MMS 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.
[69 FR 3510, Jan. 26, 2004, as amended at 69 FR 24054, Apr. 30, 2004.
Redesignated and amended at 69512, 69514, Nov. 18, 2008]
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.
----------------------------------------------------------------------------------------------------------------
the applicable threshold
For a lease located in water . . . And issued . . . price is . . .
----------------------------------------------------------------------------------------------------------------
(1) Partly or entirely less than 200 before December 18, 2008,................. $10.15 per MMBtu, adjusted
meters deep, annually after calendar year
2007 for inflation.
(2) Partly or entirely less than 200 after December 18, 2008, $4.55 per MMBtu, adjusted
meters deep, annually after calendar year
2007 for inflation unless
the lease terms prescribe a
different price threshold.
[[Page 28]]
(3) Entirely more than 200 meters and on any date, $4.55 per MMBtu, adjusted
entirely less than 400 meters deep, annually after calendar year
2007 for inflation 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 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 Sec. 218.54 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.
[73 FR 69514, Nov. 18, 2008]
Sec. 203.49 May I substitute the deep gas drilling provisions in
Sec. 203.0 and Sec. Sec. 203.40 through 203.47 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 MMS 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.
[69 FR 3510, Jan. 26, 2004. Redesignated and amended at 73 FR 69512,
69515, Nov. 18, 2008]
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.
[63 FR 2618, Jan. 16, 1998, as amended at 63 FR 57249, Oct. 27, 1998]
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 MMS Regional Director. Your MMS regional office will provide
specific guidance on the report formats. A
[[Page 29]]
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 MMS grant?
(a) If we approve your application and you meet certain conditions,
we 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.
[[Page 30]]
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).
[73 FR 69515, Nov. 18, 2008]
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 250, 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 MMS 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.
(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
MMS 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 MMS 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.
[73 FR 69515, Nov. 18, 2008]
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
[[Page 31]]
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.
[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1875, Jan. 15, 2002]
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.
[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1875, Jan. 15, 2002]
Sec. 203.65 How long will MMS 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 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--
------------------------------------------------------------------------
We need more records to audit sunk Ask to extend the 120-day or 180-
costs. 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.
We cannot evaluate your application Add another 30 days. We may add
for a valid reason, such as more than 30 days, but only if you
missing vital information or agree.
inconsistent or inconclusive
supporting data.
We need more data, explanations, or Ask to extend the 120-day or 180-
revision. 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.
[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1875, Jan. 15, 2002]
Sec. 203.66 What happens if MMS 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
If you apply for royalty relief decide within the As long as you
for time specified
------------------------------------------------------------------------
(a) An authorized field......... You get the Abide by Sec.
minimum Sec. 203.70 and
suspension 203.76.
volumes specified
in Sec. 203.69.
(b) An expansion project........ You get a royalty Abide by Sec.
suspension for Sec. 203.70 and
the first year of 203.76.
production.
[[Page 32]]
(c) A development project....... You get a royalty Abide by Sec.
suspension for Sec. 203.70 and
initial 203.76.
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.
------------------------------------------------------------------------
[67 FR 1875, Jan. 15, 2002]
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.
[67 FR 1876, Jan. 15, 2002]
Sec. 203.68 What pre-application costs will MMS 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 Whether a development project
discovery well on each lease. or an expansion project needs
relief to become economic.
------------------------------------------------------------------------
[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1876, Jan. 15, 2002]
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
[[Page 33]]
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 10 percent of the
leases offshore Alaska, the combined median of the
royalty suspension distribution of
volumes (or the known recoverable
volume equivalent resources upon
based on the data which MMS based
in your approved approval of your
application for application from
other forms of all reservoirs
royalty suspension) included in the
with which MMS project.
issued the leases
participating in
the application
that have or plan a
well into a
reservoir
identified in the
application,
(2) Leases offshore Alaska A volume equal to 10
or other deep water GOM percent of the
leases issued in sales median of the
after November 28, 2000, distribution of
known recoverable
resources upon
which MMS 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 MMS 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.
[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1876, Jan. 15, 2002; 73
FR 58472, Oct. 7, 2008; 73 FR 69515, Nov. 18, 2008]
Sec. 203.70 What information must I provide after MMS 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 MMS Regional Office for your region will prescribe the
formats.
------------------------------------------------------------------------
Due date
Required report When due to MMS extensions
------------------------------------------------------------------------
(a) Fabricator's confirmation Within 18 months MMS Director may
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 justification
of production from you, the MMS
that is subject Regional Director
to the approved for your region
royalty may extend the
suspension volume. due date up to 30
days.
------------------------------------------------------------------------
[67 FR 1876, Jan. 15, 2002, as amended at 73 FR 69515, Nov. 18, 2008]
[[Page 34]]
Sec. 203.71 How does MMS 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 lease We will not change Production from
to your authorized field after your authorized the assigned
we approve relief. field's royalty eligible lease(s)
suspension volume counts toward the
determined under royalty
Sec. 203.69. suspension volume
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 Sec.
260.114 of this
chapter.
(2) We assign a pre-Act or post- We will not change The assigned
November 2000 deep water lease your field's lease(s) may
to your field after we approve royalty share in any
your application. suspension volume. remaining royalty
relief by 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 that In our evaluation (i) You toll the
you operate to your field while of your time period for
we are evaluating your authorized field, evaluation until
application. we will take into you modify your
account the value application to be
of any royalty consistent with
relief the added the newly
lease already has constituted
under Sec. field;
260.114 or its (ii) We have an
lease document. additional 60
If we find your days to review
authorized field the new
still needs information; and
additional (iii) The assigned
royalty pre-Act lease or
suspension royalty
volume, that suspension lease
volume will be at shares the
least the royalty
combined royalty suspension we
suspension volume grant to the
to which all newly constituted
added leases on field. An
the field are eligible lease
entitled, or the does not share
minimum the royalty
suspension volume suspension we
of the authorized grant to the new
field, whichever field. If you do
is greater. not agree to
toll, we will
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 Sec.
260.114 of this
chapter.
(4) We assign another operator's We will change (i) You both toll
lease to your field while we your field's the time period
are evaluating your application. minimum for evaluation
suspension volume until both of you
provided the modify your
assigned lease application to be
joins the consistent with
application and the new field;
is entitled to a (ii) We have an
larger minimum additional 60
suspension volume. days 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.
[[Page 35]]
(5) We reassign a well on a pre- The past For any field
Act, eligible, or royalty production from based relief, the
suspension lease from field A the well counts past production
to field B. toward the for that well
royalty will not count
suspension volume toward any
that we grant royalty
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
Sec. 260.114 if
the well is on an
eligible lease or
under Sec.
260.124 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.
[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1877, Jan. 15, 2002; 73
FR 58472, Oct. 7, 2008]
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 MMS 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
(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.
[[Page 36]]
(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.
[63 FR 2618, Jan. 16, 1998; 63 FR 24747, May 5, 1998, as amended at 67
FR 1878, Jan. 15, 2002]
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 MMS 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 within18 months of the date we approved your
application, unless the MMS 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 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
[[Page 37]]
granting royalty relief under this section. You must pay royalties and
late-payment interest determined under 30 U.S.C. 1721 and Sec. 218.54
of this chapter on all volumes for which you used the royalty
suspension. You also may be subject to penalties under other provisions
of law.
[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1878, Jan. 15, 2002]
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 MMS Regional office for your region.
[73 FR 69516, Nov. 18, 2008]
Sec. 203.78 Do I keep relief approved by MMS under
Sec. Sec. 203.60-203.77 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 MMS 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.
----------------------------------------------------------------------------------------------------------------
For . . . The base price threshold is . . .
----------------------------------------------------------------------------------------------------------------
(1) Pre-Act leases in the GOM, set by statute.
(2) Post-November 2000 deep water leases in indicated in your original lease agreement or, if none, those in
the GOM or leases offshore of Alaska for the Notice of Sale under which your lease was issued.
which the lease or Notice of Sale set a base
price threshold,
(3) Post-November 2000 deep water leases in the threshold set by statute for pre-Act leases.
the GOM or leases offshore of Alaska 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) 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
Sec. 218.54 of this chapter) 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
Sec. 218.54 of this chapter) 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):
(1) Of oil if the arithmetic average of the closing prices for the
current calendar year is $28.00 per barrel or less,
[[Page 38]]
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 part 230 of this chapter 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.
[73 FR 69516, Nov. 18, 2008]
Sec. 203.79 How do I appeal MMS'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 MMS Director a letter within 15
days that also states your reasons. The MMS 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 MMS Director and stating your reasons. The MMS 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 means 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.
[67 FR 1879, Jan. 15, 2002, as amended at 73 FR 69516, Nov. 18, 2008]
[[Page 39]]
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- ------------------------------------------
Required reports life Expansion Pre-act Development
lease project lease project
----------------------------------------------------------------------------------------------------------------
(1) Administrative information Report..................... X X X X
(2) Net revenue & relief justification report............. X
(3) Economic viability & relief justification report (RSVP ......... X X X
model imputs 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
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(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 MMS 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.
[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1879, Jan. 15, 2002; 73
FR 69516, Nov. 18, 2008]
Sec. 203.82 What is MMS'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(b) and part 250 of this chapter.
[[Page 40]]
(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.
(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, Minerals
Management Service, Mail Stop 5438, 1849 C Street, NW., Washington, DC
20240.
[63 FR 2618, Jan. 16, 1998, as amended at 65 FR 2875, Jan. 19, 2000; 74
FR 46907, Sept. 14, 2009]
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 we 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).
[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1879, Jan. 15, 2002]
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, MMS. 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 220.013 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.
[63 FR 2618, Jan. 16, 1998, as amended at 63 FR 57249, Oct. 27, 1998]
[[Page 41]]
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, MMS. Clearly justify each parameter you set
in every scenario you 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 MMS 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;
[[Page 42]]
(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;
(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.
[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1879, Jan. 15, 2002]
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
[[Page 43]]
(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 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.
[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1880, Jan. 15, 2002]
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;
[[Page 44]]
(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 existed on the application submission date).
[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1880, Jan. 15, 2002]
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 MMS
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.
[63 FR 2618, Jan. 16, 1998, as amended at 73 FR 69516, Nov. 18, 2008]
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).
[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1880, Jan. 15, 2002]
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_DISTRIBUTION AND DISBURSEMENT OF ROYALTIES, RENTALS, AND BONUSES--Table of Contents
Subpart A--General Provision [Reserved]
Subpart B--Oil and Gas, General [Reserved]
Subpart C [Reserved]
Subpart D_Oil and Gas, Offshore
Sec.
219.410 What does this subpart contain?
219.411 What definitions apply to this subpart?
219.412 How will the qualified OCS revenues be divided?
219.413 How will the coastal political subdivisions of Gulf producing
States share in the qualified OCS revenues?
219.414 How will MMS determine each Gulf producing State's share of the
qualified OCS revenues?
219.415 How will bonus and royalty credits affect revenues allocated to
Gulf producing States?
219.416 How will the qualified OCS revenues be allocated to coastal
political subdivisions within the Gulf producing States?
219.417 How will MMS disburse qualified OCS revenues to the coastal
political subdivisions if, during any fiscal year, there are
no applicable leased tracts in
[[Page 45]]
the 181 Area in the Eastern Gulf of Mexico Planning Area?
219.418 When will funds be disbursed to Gulf producing States and
eligible coastal political subdivisions?
Authority: Section 104, Pub. L. 97-451, 96 Stat. 2451 (30 U.S.C.
1714), Pub. L. 109-432, Div C, Title I, 120 Stat. 3000.
Source: 49 FR 37347, Sept. 21, 1984, unless otherwise noted.
Subpart A--General Provisions [Reserved]
Subpart B--Oil and Gas, General [Reserved]
Subpart C [Reserved]
Subpart D_Oil and Gas, Offshore
Source: 73 FR 78629, Dec. 23, 2008, unless otherwise noted.
Sec. 219.410 What does this subpart contain?
(a) The Gulf of Mexico Energy Security Act of 2006 (GOMESA) directs
the Secretary of the Interior to disburse a portion of the rentals,
royalties, bonus, and other sums derived from certain Outer Continental
Shelf (OCS) leases in the Gulf of Mexico (GOM) to the States of Alabama,
Louisiana, Mississippi, and Texas (collectively identified as the Gulf
producing States); to eligible coastal political subdivisions within
those States; and to the Land and Water Conservation Fund. Shared GOMESA
revenues are reserved for the following purposes:
(1) Projects and activities for the purposes of coastal protection,
including conservation, coastal restoration, hurricane protection, and
infrastructure directly affected by coastal wetland losses.
(2) Mitigation of damage to fish, wildlife, or natural resources.
(3) Implementation of a federally-approved marine, coastal, or
comprehensive conservation management plan.
(4) Mitigation of the impact of OCS activities through the funding
of onshore infrastructure projects.
(5) Planning assistance and administrative costs not-to-exceed 3
percent of the amounts received.
(b) This subpart sets forth the formula and methodology MMS will use
to determine the amount of revenues to be disbursed and the amount to be
allocated to each Gulf producing State and each eligible coastal
political subdivision. For questions related to the revenue sharing
provisions in this subpart, please contact: Chief, Financial Management,
Minerals Revenue Management; P.O. Box 25165; Denver Federal Center,
Building 85; MS-350B1; Denver, CO 80225-0165, or at (303) 231-3429.
Sec. 219.411 What definitions apply to this subpart?
Terms in this subpart have the following meaning:
181 Area means the area identified in map 15, page 58, of the
Proposed Final Outer Continental Shelf Oil and Gas Leasing Program for
1997-2002, dated August 1996, of the Minerals Management Service,
available in the Office of the Director of the Minerals Management
Service, excluding the area offered in OCS Lease Sale 181, held on
December 5, 2001.
181 Area in the Eastern Planning Area is comprised of the area of
overlap of the two geographic areas defined as the ``181 Area'' and the
``Eastern Planning Area.''
181 South Area means any area--
(1) Located--
(i) South of the 181 Area;
(ii) West of the Military Mission Line; and
(iii) In the Central Planning Area;
(2) Excluded from the Proposed Final Outer Continental Shelf Oil and
Gas Leasing Program for 1997-2002, dated August 1996, of the Minerals
Management Service; and
(3) Included in the areas considered for oil and gas leasing, as
identified in map 8, page 37, of the document entitled, Draft Proposed
Program Outer Continental Shelf Oil and Gas Leasing Program 2007-2012,
dated February 2006.
Applicable leased tract means a tract that is subject to a lease
under section 8 of the Outer Continental Shelf Lands Act for the purpose
of drilling for, developing, and producing oil or natural gas resources,
and is located fully or partially in either the 181 Area in the
[[Page 46]]
Eastern Planning Area, or in the 181 South Area.
Central Planning Area means the Central Gulf of Mexico Planning Area
of the Outer Continental Shelf, as designated in the document entitled,
Draft Proposed Program Outer Continental Shelf Oil and Gas Leasing
Program 2007-2012, dated February 2006.
Coastal political subdivision means a political subdivision of a
Gulf producing State any part of which political subdivision is--
(1) Within the coastal zone (as defined in section 304 of the
Coastal Zone Management Act of 1972 (16 U.S.C. 1453)) of the Gulf
producing State as of December 20, 2006; and
(2) Not more than 200 nautical miles from the geographic center of
any leased tract.
Coastline 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. This is the same definition
used in section 2 of the Submerged Lands Act (43 U.S.C. 1301).
Distance means the minimum great circle distance.
Eastern Planning Area means the Eastern Gulf of Mexico Planning Area
of the Outer Continental Shelf, as designated in the document entitled,
Draft Proposed Program Outer Continental Shelf Oil and Gas Leasing
Program 2007-2012, dated February 2006.
Gulf producing State means each of the States of Alabama, Louisiana,
Mississippi, and Texas.
Leased tract means any tract that is subject to a lease under
section 6 or 8 of the Outer Continental Shelf Lands Act for the purpose
of drilling for, developing, and producing oil or natural gas resources.
Military Mission Line means the north-south line at 86[deg]41[min]
W. longitude.
Qualified OCS revenues mean--
(1) The term qualified OCS revenues means, in the case of each of
fiscal years 2007 through 2016, all rentals, royalties, bonus bids, and
other sums received by the U.S. from leases entered into on or after
December 20, 2006, located:
(i) In the 181 Area in the Eastern Planning Area; and
(ii) In the 181 South Area.
(iii) For applicable leased tracts intersected by the planning area
administrative boundary line (e.g., separating the GOM Central Planning
Area from the Eastern Planning Area), only the percent of revenues
equivalent to the percent of surface acreage in the 181 Area in the
Eastern Planning Area will be considered qualified OCS revenues.
(2) Exclusions to the term qualified OCS revenues include:
(i) Revenues from the forfeiture of a bond or other surety securing
obligations other than royalties;
(ii) Civil penalties;
(iii) Royalties taken by the Secretary in-kind and not sold;
(iv) User fees; and
(v) Lease revenues explicitly circumscribed from GOMESA revenue
sharing by statute or appropriations law.
Sec. 219.412 How will the qualified OCS revenues be divided?
For each of the fiscal years 2007 through 2016, 50 percent of the
qualified OCS revenues will be placed in a special U.S. Treasury account
from which 75 percent of the revenues will be disbursed to the Gulf
producing States, and 25 percent will be disbursed to the Land and Water
Conservation Fund. Each Gulf producing State will receive at least 10
percent of the qualified OCS revenues available for allocation to the
Gulf producing States each fiscal year.
Revenue Distribution of Qualified OCS Revenues Under GOMESA
------------------------------------------------------------------------
Percentage of
qualified OCS
Recipient of qualified OCS revenues revenues
(percent)
------------------------------------------------------------------------
U.S. Treasury (General Fund)......................... 50
Land and Water Conservation Fund..................... 12.5
Gulf Producing States................................ 30
Gulf Producing State Coastal Political Subdivisions.. 7.5
------------------------------------------------------------------------
Sec. 219.413 How will the coastal political subdivisions of Gulf
producing States share in the qualified OCS revenues?
Of the revenues allocated to a Gulf producing State, 20 percent will
be distributed to the coastal political subdivisions within that State.
[[Page 47]]
Sec. 219.414 How will MMS determine each Gulf producing State's share of the qualified OCS revenues?
(a) The MMS will determine the geographic centers of each applicable
leased tract and, using the great circle distance method, will determine
the closest distance from the geographic centers of each applicable
leased tract to each Gulf producing State's coastline.
(b) Based on these distances, we will calculate the qualified OCS
revenues to be disbursed to each Gulf producing State using the
following procedure:
(1) For each Gulf producing State, we will calculate and total, over
all applicable leased tracts, the mathematical inverses of the distances
between the points on the State's coastline that are closest to the
geographic centers of the applicable leased tracts and the geographic
centers of the applicable leased tracts. For applicable leased tracts
intersected by the planning area administrative boundary line, the
geographic center used for the inverse distance determination will be
the geographic center of the entire lease as if it were not intersected.
(2) For each Gulf producing State, we will divide the sum of each
State's inverse distances, from all applicable leased tracts, by the sum
of the inverse distances from all applicable leased tracts across all
four Gulf producing States. We will multiply the result by the amount of
qualified OCS revenues to be shared as shown below. In the formulas,
IAL, ILA, IMS, and ITX represent the sum of the inverses of the closest
distances between Alabama, Louisiana, Mississippi, and Texas and all
applicable leased tracts, respectively.
Alabama Share = (IAL / (IAL + ILA + IMS + ITX)) x Qualified OCS Revenues
Louisiana Share = (ILA / (IAL + ILA + IMS + ITX)) x Qualified OCS
Revenues
Mississippi Share = (IMS / (IAL + ILA + IMS + ITX)) x Qualified OCS
Revenues
Texas Share = (ITX / (IAL + ILA + IMS + ITX)) x Qualified OCS Revenues
(3) If in any fiscal year, this calculation results in less than a
10 percent allocation of the qualified OCS revenues to any Gulf
producing State, we will recalculate the distribution. We will allocate
10 percent of the qualified OCS revenues to the State and recalculate
the other States' shares of the remaining qualified OCS revenues
omitting the State receiving the 10 percent minimum share and its 10
percent share from the calculation.
Sec. 219.415 How will bonus and royalty credits affect revenues allocated
to Gulf producing States?
If bonus and royalty credits issued under Section 104(c) of the Gulf
of Mexico Energy Security Act are used to pay bonuses or royalties on
leases in the 181 Area located in the Eastern Planning Area and the 181
South Area, then there will be a corresponding reduction in qualified
OCS revenues available for distribution.
Sec. 219.416 How will the qualified OCS revenues be
allocated to coastal political subdivisions within the Gulf producing States?
The MMS will disburse funds to the coastal political subdivisions in
accordance with the following criteria:
(a) Twenty-five percent of the qualified OCS revenues will be
allocated to a Gulf producing State's coastal political subdivisions in
the proportion that each coastal political subdivision's population
bears to the population of all coastal political subdivisions in the
producing State;
(b) Twenty-five percent of the qualified OCS revenues will be
allocated to a Gulf producing State's coastal political subdivisions in
the proportion that each coastal political subdivision's miles of
coastline bears to the number of miles of coastline of all coastal
political subdivisions in the producing State. Except that, for the
State of Louisiana, proxy coastline lengths for coastal political
subdivisions without a coastline will be considered to be \1/3\ the
average length of the coastline of all political subdivisions within
Louisiana having a coastline.
(c) Fifty percent of the revenues will be allocated to a Gulf
producing State's coastal political subdivisions in amounts that are
inversely proportional to the respective distances between the
geographic center of each applicable leased tract and the point in each
coastal political subdivision that is closest to the geographic center
of each applicable leased tract. Except that, an applicable leased tract
will be
[[Page 48]]
excluded from this calculation if any portion of the tract is located in
a geographic area that was subject to a leasing moratorium on January 1,
2005, unless that tract was in production on that date.
Sec. 219.417 How will MMS disburse qualified OCS revenues to the coastal
political subdivisions if, during any fiscal year, there are no applicable leased
tracts in the 181 Area in the Eastern Gulf of Mexico Planning
Area?
If, during any fiscal year, there are no applicable leased tracts in
the 181 Area in the Eastern Gulf of Mexico Planning Area, MMS will
disburse funds to the coastal political subdivisions in accordance with
the following criteria:
(a) Fifty percent of the revenues will be allocated to a Gulf
producing State's coastal political subdivisions in the proportion that
each coastal political subdivision's population bears to the population
of all coastal political subdivisions in the State; and
(b) Fifty percent of the revenues will be allocated to a Gulf
producing State's coastal political subdivisions in the proportion that
each coastal political subdivision's miles of coastline bears to the
number of miles of coastline of all coastal political subdivisions in
the State. Except that, for the State of Louisiana, proxy coastline
lengths for coastal political subdivisions without a coastline will be
considered to be \1/3\ the average length of the coastline of all
political subdivisions within Louisiana having a coastline.
Sec. 219.418 When will funds be disbursed to Gulf producing States and
eligible coastal political subdivisions?
(a) The MMS will disburse allocated funds in the fiscal year after
MMS collects the qualified OCS revenues. For example, MMS will disburse
funds in fiscal year 2010 from the qualified OCS revenues collected
during fiscal year 2009.
(b) We intend to disburse funds on or before March 31st of the year
following the fiscal year of qualified OCS revenues.
[[Page 49]]
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 MMS 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 and operate electrical equipment?
250.115 How do I determine well producibility?
250.116 How do I determine producibility if my well is in the Gulf of
Mexico?
250.117 How does a determination of well producibility affect royalty
status?
250.118 Will MMS approve gas injection?
250.119 Will MMS approve subsurface gas storage?
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 Will MMS allow gas storage on unleased lands?
250.124 Will MMS 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 MMS conduct inspections?
250.131 Will MMS notify me before conducting an inspection?
250.132 What must I do when MMS conducts an inspection?
250.133 Will MMS reimburse me for my expenses related to inspections?
Disqualification
250.135 What will MMS do if my operating performance is unacceptable?
250.136 How will MMS 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 How do I designate an operator?
250.144 How do I designate a new operator when a designation of operator
terminates?
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?
Right-of-Use and Easement
250.160 When will MMS grant me a right-of-use and easement, and what
requirements must I meet?
250.161 What else must I submit with my application?
250.162 May I continue my right-of-use and easement after the
termination of any lease on which it is situated?
250.163 If I have a State lease, will MMS grant me a right-of-use and
easement?
250.164 If I have a State lease, what conditions apply for a right-of-
use and easement?
250.165 If I have a State lease, what fees do I have to pay for a right-
of-use and easement?
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250.166 If I have a State lease, what surety bond must I have for a
right-of-use and easement?
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?
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 When may the Secretary cancel my lease and when am I compensated
for cancellation?
250.182 When may the Secretary cancel a lease at the exploration stage?
250.183 When may MMS or the Secretary extend or cancel a lease at the
development and production stage?
250.184 What is the amount of compensation for lease cancellation?
250.185 When is there no compensation for a lease cancellation?
Information and Reporting Requirements
250.186 What reporting information and report forms must I submit?
250.187 What are MMS' incident reporting requirements?
250.188 What incidents must I report to MMS 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 MMS 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 apparent violations.
250.194 How must I protect archaeological resources?
250.195 What notification does MMS 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 What criteria must the Exploration Plan (EP), Development and
Production Plan (DPP), or Development Operations Coordination
Document (DOCD) meet?
250.203 Where can wells be located under an EP, DPP, or DOCD?
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?
250.206 How do I submit the EP, DPP, or DOCD?
Ancillary Activities
250.207 What ancillary activities may I conduct?
250.208 If I conduct ancillary activities, what notices must I provide?
250.209 What is the MMS review process for the notice?
250.210 If I conduct ancillary activities, what reporting and data/
information retention requirements must I satisfy?
Contents of Exploration Plans (EP)
250.211 What must the EP include?
250.212 What information must accompany the EP?
250.213 What general information must accompany the EP?
250.214 What geological and geophysical (G&G) information must accompany
the EP?
250.215 What hydrogen sulfide (H2S) information must
accompany the EP?
250.216 What biological, physical, and socioeconomic information must
accompany the EP?
250.217 What solid and liquid wastes and discharges information and
cooling water intake information must accompany the EP?
250.218 What air emissions information must accompany the EP?
250.219 What oil and hazardous substance spills information must
accompany the EP?
[[Page 51]]
250.220 If I propose activities in the Alaska OCS Region, what planning
information must accompany the EP?
250.221 What environmental monitoring information must accompany the EP?
250.222 What lease stipulations information must accompany the EP?
250.223 What mitigation measures information must accompany the EP?
250.224 What information on support vessels, offshore vehicles, and
aircraft you will use must accompany the EP?
250.225 What information on the onshore support facilities you will use
must accompany the EP?
250.226 What Coastal Zone Management Act (CZMA) information must
accompany the EP?
250.227 What environmental impact analysis (EIA) information must
accompany the EP?
250.228 What administrative information must accompany the EP?
Review and Decision Process for the EP
250.231 After receiving the EP, what will MMS do?
250.232 What actions will MMS take after the EP is deemed submitted?
250.233 What decisions will MMS make on the EP and within what
timeframe?
250.234 How do I submit a modified EP or resubmit a disapproved EP, and
when will MMS make a decision?
250.235 If a State objects to the EP's coastal zone consistency
certification, what can I do?
Contents of Development and Production Plans (DPP) and Development
Operations Coordination Documents (DOCD)
250.241 What must the DPP or DOCD include?
250.242 What information must accompany the DPP or DOCD?
250.243 What general information must accompany the DPP or DOCD?
250.244 What geological and geophysical (G&G) information must accompany
the DPP or DOCD?
250.245 What hydrogen sulfide (H2S) information must
accompany the DPP or DOCD?
250.246 What mineral resource conservation information must accompany
the DPP or DOCD?
250.247 What biological, physical, and socioeconomic information must
accompany the DPP or DOCD?
250.248 What solid and liquid wastes and discharges information and
cooling water intake information must accompany the DPP or
DOCD?
250.249 What air emissions information must accompany the DPP or DOCD?
250.250 What oil and hazardous substance spills information must
accompany the DPP or DOCD?
250.251 If I propose activities in the Alaska OCS Region, what planning
information must accompany the DPP?
250.252 What environmental monitoring information must accompany the DPP
or DOCD?
250.253 What lease stipulations information must accompany the DPP or
DOCD?
250.254 What mitigation measures information must accompany the DPP or
DOCD?
250.255 What decommissioning information must accompany the DPP or DOCD?
250.256 What related facilities and operations information must
accompany the DPP or DOCD?
250.257 What information on the support vessels, offshore vehicles, and
aircraft you will use must accompany the DPP or DOCD?
250.258 What information on the onshore support facilities you will use
must accompany the DPP or DOCD?
250.259 What sulphur operations information must accompany the DPP or
DOCD?
250.260 What Coastal Zone Management Act (CZMA) information must
accompany the DPP or DOCD?
250.261 What environmental impact analysis (EIA) information must
accompany the DPP or DOCD?
250.262 What administrative information must accompany the DPP or DOCD?
Review and Decision Process for the DPP or DOCD
250.266 After receiving the DPP or DOCD, what will MMS do?
250.267 What actions will MMS take after the DPP or DOCD is deemed
submitted?
250.268 How does MMS respond to recommendations?
250.269 How will MMS evaluate the environmental impacts of the DPP or
DOCD?
250.270 What decisions will MMS make on the DPP or DOCD and within what
timeframe?
250.271 For what reasons will MMS disapprove the DPP or DOCD?
250.272 If a State objects to the DPP's or DOCD's coastal zone
consistency certification, what can I do?
250.273 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
250.280 How must I conduct activities under the approved EP, DPP, or
DOCD?
250.281 What must I do to conduct activities under the approved EP, DPP,
or DOCD?
250.282 Do I have to conduct post-approval monitoring?
[[Page 52]]
250.283 When must I revise or supplement the approved EP, DPP, or DOCD?
250.284 How will MMS require revisions to the approved EP, DPP, or DOCD?
250.285 How do I submit revised and supplemental EPs, DPPs, or DOCDs?
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?
Conservation Information Documents (CID)
250.296 When and how must I submit a CID or a revision to a CID?
250.297 What information must a CID contain?
250.298 How long will MMS take to evaluate and make a decision on the
CID?
250.299 What operations require approval of the CID?
Subpart C_Pollution Prevention and Control
250.300 Pollution prevention.
250.301 Inspection of facilities.
250.302 Definitions concerning air quality.
250.303 Facilities described in a new or revised Exploration Plan or
Development and Production Plan.
250.304 Existing facilities.
Subpart D_Oil and Gas Drilling Operations
General Requirements
250.400 Who is subject to the requirements of this subpart?
250.401 What must I do to keep wells under control?
250.402 When and how must I secure a well?
250.403 What drilling unit movements must I report?
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 What additional safety measures must I take when I conduct
drilling operations on a platform that has producing wells or
has other hydrocarbon flow?
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 and BOP descriptions?
250.417 What must I provide if I plan to use a mobile offshore drilling
unit (MODU)?
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 pressure testing casing?
250.424 What are the requirements for prolonged drilling operations?
250.425 What are the requirements for pressure testing liners?
250.426 What are the recordkeeping requirements for casing and liner
pressure tests?
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?
Blowout Preventer (BOP) System Requirements
250.440 What are the general requirements for BOP systems and system
components?
[[Page 53]]
250.441 What are the requirements for a surface BOP stack?
250.442 What are the requirements for a subsea BOP system?
250.443 What associated systems and related equipment must all BOP
systems include?
250.444 What are the choke manifold requirements?
250.445 What are the requirements for kelly valves, inside BOPs, and
drill-string safety valves?
250.446 What are the BOP maintenance and inspection requirements?
250.447 When must I pressure test the BOP system?
250.448 What are the BOP pressure tests requirements?
250.449 What additional BOP testing requirements must I meet?
250.450 What are the recordkeeping requirements for BOP tests?
250.451 What must I do in certain situations involving BOP equipment or
systems?
Drilling Fluid Requirements
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 (AMP) or
an End of Operations Report to MMS?
250.466 What records must I keep?
250.467 How long must I keep records?
250.468 What well records am I required to submit?
250.469 What other well records could I be required to submit?
Hydrogen Sulfide
250.490 Hydrogen sulfide.
Subpart E_Oil and Gas Well-Completion Operations
250.500 General requirements.
250.501 Definition.
250.502 Equipment movement.
250.503 Emergency shutdown system.
250.504 Hydrogen sulfide.
250.505 Subsea completions.
250.506 Crew instructions.
250.507-250.508 [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 Blowout prevention equipment.
250.516 Blowout preventer system tests, inspections, and maintenance.
250.517 Tubing and wellhead equipment.
Casing Pressure Management
250.518 What are the requirements for casing pressure management?
250.519 How often do I have to monitor for casing pressure?
250.520 When do I have to perform a casing diagnostic test?
250.521 How do I manage the thermal effects caused by initial production
on a newly completed or recompleted well?
250.522 When do I have to repeat casing diagnostic testing?
250.523 How long do I keep records of casing pressure and diagnostic
tests?
250.524 When am I required to take action from my casing diagnostic
test?
250.525 What do I submit if my casing diagnostic test requires action?
250.526 What must I include in my notification of corrective action?
250.527 What must I include in my casing pressure request?
250.528 What are the terms of my casing pressure request?
250.529 What if my casing pressure request is denied?
250.530 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 Equipment movement.
250.603 Emergency shutdown system.
250.604 Hydrogen sulfide.
250.605 Subsea workovers.
250.606 Crew instructions.
250.607-250.608 [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.
250.613 Approval and reporting for well-workover operations.
[[Page 54]]
250.614 Well-control fluids, equipment, and operations.
250.615 Blowout prevention equipment.
250.616 Blowout preventer system testing, records, and drills.
250.617 What are my BOP inspection and maintenance requirements?
250.618 Tubing and wellhead equipment.
250.619 Wireline operations.
Subpart G [Reserved]
Subpart H_Oil and Gas Production Safety Systems
250.800 General requirements.
250.801 Subsurface safety devices.
250.802 Design, installation, and operation of surface production-safety
systems.
250.803 Additional production system requirements.
250.804 Production safety-system testing and records.
250.805 Safety device training.
250.806 Safety and pollution prevention equipment quality assurance
requirements.
250.807 Additional requirements for subsurface safety valves and related
equipment installed in high pressure high temperature (HPHT)
environments.
250.808 Hydrogen sulfide.
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?
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 MMS 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 Abandonment and out-of-service requirements for DOI pipelines.
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 Bond requirements for pipeline right-of-way holders.
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.
[[Page 55]]
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 When must I conduct a static bottomhole pressure survey?
Classifying Reservoirs
250.1154 How do I determine if my reservoir is sensitive?
250.1155 What information must I submit for sensitive reservoirs?
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?
Flaring, 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.
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 MMS require unitization?
Subpart N_Outer Continental Shelf Civil Penalties
Outer Continental Shelf Lands Act Civil Penalties
250.1400 How does MMS begin the civil penalty process?
250.1401 Index table.
250.1402 Definitions.
250.1403 What is the maximum civil penalty?
250.1404 Which violations will MMS review for potential civil penalties?
250.1405 When is a case file developed?
250.1406 When will MMS 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 the Bureau of Ocean Energy Management, Regulation, and
Enforcement (BOEMRE) 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 BOEMRE inform me of violations without a period to
correct?
[[Page 56]]
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 BOEMRE 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 BOEMRE reduce my penalty once it is assessed?
250.1477 How may BOEMRE collect the penalty?
Criminal Penalties
250.1480 May the United States criminally prosecute me for violations
under Federal oil and gas leases?
Bonding Requirements
250.1490 What standards must my BOEMRE-specified surety instrument meet?
250.1491 How will BOEMRE determine the amount of my bond or other surety
instrument?
Financial Solvency Requirements
250.1495 How do I demonstrate financial solvency?
250.1496 How will BOEMRE determine if I am financially solvent?
250.1497 When will BOEMRE monitor my financial solvency?
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 MMS measure training results?
250.1508 What must I do when MMS administers written or oral tests?
250.1509 What must I do when MMS administers or requires hands-on,
simulator, or other types of testing?
250.1510 What will MMS 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.
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?
[[Page 57]]
250.1702 When do I accrue decommissioning obligations?
250.1703 What are the general requirements for decommissioning?
250.1704 When must I submit decommissioning applications and reports?
Permanently Plugging Wells
250.1710 When must I permanently plug all wells on a lease?
250.1711 When will MMS 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 MMS 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 After I permanently plug a well, what information must I
submit?
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 MMS 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?
250.1901 What is the goal of my SEMS program?
250.1902 What must I include in my SEMS program?
250.1903 Definitions.
250.1904 Documents incorporated by reference
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 criteria for hazards analyses 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 criteria for training 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?
250.1921-250.1923 [Reserved]
250.1924 How will BOEMRE determine if my SEMS program is effective?
250.1925 May BOEMRE direct me to conduct additional audits?
250.1926 What qualifications must an independent third party or my
designated and qualified personnel meet?
250.1927 What happens if BOEMRE 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?
[[Page 58]]
Authority: 30 U.S.C. 1751; 31 U.S.C. 9701; 43 U.S.C. 1334.
Source: 53 FR 10690, Apr. 1, 1988, unless otherwise noted.
Redesignated at 63 FR 29479, May 29, 1998.
Editorial Note: Nomenclature changes to part 250 appear at 71 FR
46399 and 46400, Aug. 14, 2006.
Subpart A_General
Source: 64 FR 72775, Dec. 28, 1999, unless otherwise noted.
Authority and Definition of Terms
Sec. 250.101 Authority and applicability.
The Secretary of the Interior (Secretary) authorized the Minerals
Management Service (MMS) 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, MMS 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) 30 CFR part 250 contains the regulations of the MMS 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 MMS 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
------------------------------------------------------------------------
Refer to 30 CFR 250
For information about subpart or
------------------------------------------------------------------------
(1) Applications for permit to drill...... D.
(2) Development and Production Plans (DPP) B.
(3) Downhole commingling.................. K.
(4) Exploration Plans (EP)................ B.
(5) Flaring............................... K.
(6) Gas measurement....................... L.
(7) Off-lease geological and geophysical 30 CFR 251.
permits.
(8) Oil spill financial responsibility 30 CFR 253.
coverage.
(9) Oil and gas production safety systems. H.
(10) Oil spill response plans............. 30 CFR 254.
(11) Oil and gas well-completion E.
operations.
(12) Oil and gas well-workover operations. F.
(13) Decommissioning Activities........... Q.
(14) Platforms and structures............. I.
(15) Pipelines and Pipeline Rights-of-Way. J.
(16) Sulphur operations................... P.
(17) Training............................. O.
(18) Unitization.......................... M.
------------------------------------------------------------------------
[64 FR 72775, Dec. 28, 1999, as amended at 67 FR 35405, May 17, 2002; 68
FR 8422, Feb. 20, 2003; 70 FR 51500, Aug. 30, 2005; 72 FR 25198, May 4,
2007]
Sec. 250.103 Where can I find more information about the requirements in this part?
MMS 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 MMS.
Sec. 250.104 How may I appeal a decision made under MMS regulations?
To appeal orders or decisions issued under MMS 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
[[Page 59]]
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 of physical and chemical properties, well
logs or charts, results from formation fluid tests, and descriptions of
hydrocarbon occurrences or hazardous conditions.
Ancillary activities means 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 MMS 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.
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.
[[Page 60]]
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 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 means approvals granted by the appropriate MMS
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 MMS of the U.S. Department of the
Interior, or an official authorized to act on the Director's behalf.
District Manager means the MMS officer with authority and
responsibility for operations or other designated program functions for
a district within an MMS 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
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 means 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 means 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. 250.303, 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 61]]
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 Sec. 250.303, 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.
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:
[[Page 62]]
(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 means 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 MMS-approved assignee of the lease, and
the owner or the MMS-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 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 includes 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 includes, 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.
[[Page 63]]
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 means 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 MMS-approved designated agent of the
lessee(s), or the holder of operating rights under an MMS-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 means 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 MMS officer with responsibility and
authority for a Region within MMS.
Regional Supervisor means the MMS officer with responsibility and
authority for operations or other designated program functions within an
MMS 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).
[[Page 64]]
Routine operations, for the purposes of subpart F, means 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.
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 means 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 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 means 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.
[64 FR 72775, Dec. 28, 1999, as amended at 68 FR 8422, Feb. 20, 2003; 70
FR 41573, July 19, 2005; 70 FR 51500, Aug. 30, 2005; 71 FR 23862, Apr.
25, 2006; 75 FR 20288, Apr. 19, 2010]
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.
[[Page 65]]
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; and
(2) Maintaining all equipment and work areas in a safe condition.
(b) You must immediately control, remove, or otherwise correct any
hazardous oil and gas accumulation or other health, safety, or fire
hazard.
(c) You must use the best available and safest technology (BAST)
whenever practical on all exploration, development, and production
operations. In general, we consider your compliance with MMS regulations
to be the use of BAST.
(d) The Director may require additional measures to ensure the use
of BAST:
(1) To avoid the failure of equipment that would have a significant
effect on safety, health, or the environment;
(2) If it is economically feasible; and
(3) If the benefits outweigh the costs.
[64 FR 72775, Dec. 28, 1999, as amended at 73 FR 20171, Apr. 15, 2008]
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), incorporated
by reference as specified in 30 CFR 250.198.
(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), incorporated by reference as specified in 30 CFR 250.198.
(d) All cranes manufactured after March 17, 2003, and installed on a
fixed platform, must meet the requirements of API Spec 2C, incorporated
by reference as specified in 30 CFR 250.198.
(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.
[68 FR 7426, Feb. 14, 2003, as amended at 72 FR 12092, Mar. 15, 2007; 74
FR 46907, Sept. 14, 2009]
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
[[Page 66]]
(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 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 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
[[Page 67]]
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.
(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 (incorporated by
reference as specified 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 (incorporated by reference as
specified 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.
[64 FR 72775, Dec. 28, 1999, as amended at 65 FR 219, Jan. 4, 2000; 68
FR 43298, July 22, 2003]
Sec. 250.115 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.
250.116 of this subpart.
(a) You must write to the Regional Supervisor asking for permission
to determine producibility.
(b) You must either:
(1) Allow the District Manager to witness each test that you conduct
under this section; or
(2) Receive the District Manager's 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. 250.116 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. 250.115 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
MMS 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.
[[Page 68]]
Sec. 250.117 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 202.53.
Sec. 250.118 Will MMS approve gas injection?
The Regional Supervisor may authorize you to inject gas on the OCS,
on and off-lease, to promote conservation of natural resources and to
prevent waste.
(a) To receive MMS 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 Will MMS approve subsurface gas storage?
The Regional Supervisor may authorize subsurface storage of gas on
the OCS, on and off-lease, for later commercial benefit. To receive MMS
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. 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
Sec. 250.119, 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 an MMS-
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 Will MMS 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. 250.160 through 250.166 of this subpart.
Sec. 250.124 Will MMS 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 MMS 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.
[[Page 69]]
Service Fee Table
------------------------------------------------------------------------
Service--processing of the
following: Fee amount 30 CFR citation
------------------------------------------------------------------------
(1) Change in Designation of $164.................. Sec.
Operator. 250.143(d).
(2) Right-of-Use and Easement $2,569................ Sec. 250.165.
for State lessee.
(3) Suspension of Operations/ $1,968................ Sec.
Suspension of Production (SOO/ 250.171(e).
SOP) Request.
(4) Exploration Plan (EP)..... $3,442 for each Sec.
surface location; no 250.211(d).
fee for revisions.
(5) Development and Production $3,971 for each well Sec.
Plan (DPP) or Development proposed; no fee for 250.241(e).
Operations Coordination revisions.
Document (DOCD).
(6) Deepwater Operations Plan. $3,336................ Sec.
250.292(p).
(7) Conservation Information $25,629............... Sec.
Document. 250.296(a).
(8) Application for Permit to $1,959 for initial Sec.
Drill (APD; Form MMS-123). applications only; no 250.410(d);
fee for revisions. Sec. 250.411;
Sec. 250.460;
Sec.
250.513(b);
Sec. 250.515;
Sec.
250.1605; Sec.
250.1617(a);
Sec.
250.1622.
(9) Application for Permit to $116.................. Sec. 250.460;
Modify (APM; Form MMS-124). Sec.
250.465(b);
Sec.
250.513(b);
Sec. 250.515;
Sec.
250.613(b);
Sec. 250.615;
Sec.
250.1618(a);
Sec.
250.1622; Sec.
250.1704(g).
(10) New Facility Production $5,030 A component is Sec.
Safety System Application for a piece of equipment 250.802(e).
facility with more than 125 or ancillary system
components. that is protected by
one or more of the
safety devices
required by API RP
14C (incorporated by
reference as
specified in Sec.
250.198); $13,238
additional fee will
be charged if MMS
deems it necessary to
visit a facility
offshore, and $6,884
to visit a facility
in a shipyard.
(11) New Facility Production $1,218 Additional fee Sec.
Safety System Application for of $8,313 will be 250.802(e).
facility with 25-125 charged if MMS deems
components. it necessary to visit
a facility offshore,
and $4,766 to visit a
facility in a
shipyard.
(12) New Facility Production $604.................. Sec.
Safety System Application for 250.802(e).
facility with fewer than 25
components.
(13) Production Safety System $561.................. Sec.
Application--Modification 250.802(e).
with more than 125 components
reviewed.
(14) Production Safety System $201.................. Sec.
Application--Modification 250.802(e).
with 25-125 components
reviewed.
(15) Production Safety System $85................... Sec.
Application--Modification 250.802(e).
with fewer than 25 components
reviewed.
(16) Platform Application-- $21,075............... Sec.
Installation--Under the 250.905(k).
Platform Verification Program.
(17) Platform Application-- $3,018................ Sec.
Installation--Fixed Structure 250.905(k).
Under the Platform Approval
Program.
(18) Platform Application-- $1,536................ Sec.
Installation--Caisson/Well 250.905(k).
Protector.
(19) Platform Application-- $3,601................ Sec.
Modification/Repair. 250.905(k).
(20) New Pipeline Application $3,283................ Sec.
(Lease Term). 250.1000(b).
(21) Pipeline Application-- $1,906................ Sec.
Modification (Lease Term). 250.1000(b).
(22) Pipeline Application-- $3,865................ Sec.
Modification (ROW). 250.1000(b).
(23) Pipeline Repair $360.................. Sec.
Notification. 250.1008(e).
(24) Pipeline Right-of-Way $2,569................ Sec.
(ROW) Grant Application. 250.1015(a).
(25) Pipeline Conversion of $219.................. Sec.
Lease Term to ROW. 250.1015(a).
(26) Pipeline ROW Assignment.. $186.................. Sec.
250.1018(b).
(27) 500 Feet From Lease/Unit $3,608................ Sec.
Line Production Request. 250.1156(a).
(28) Gas Cap Production $4,592................ Sec. 250.1157.
Request.
(29) Downhole Commingling $5,357................ Sec.
Request. 250.1158(a).
(30) Complex Surface $3,760................ Sec.
Commingling and Measurement 250.1202(a);
Application. Sec.
250.1203(b);
Sec.
250.1204(a).
[[Page 70]]
(31) Simple Surface $1,271................ Sec.
Commingling and Measurement 250.1202(a);
Application. Sec.
250.1203(b);
Sec.
250.1204(a).
(32) Voluntary Unitization $11,698............... Sec.
Proposal or Unit Expansion. 250.1303(d).
(33) Unitization Revision..... $831.................. Sec.
250.1303(d).
(34) Application to Remove a $4,342................ Sec. 250.1727.
Platform or Other Facility.
(35) Application to $1,059................ Sec.
Decommission a Pipeline 250.1751(a) or
(Lease Term). Sec.
250.1752(a).
(36) Application to $2,012................ 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.
[70 FR 49875, Aug. 25, 2005, as amended at 71 FR 40909, July 19, 2006;
72 FR 25199, May 4, 2007; 73 FR 49946, Aug. 25, 2008; 75 FR 20288, Apr.
19, 2010]
Sec. 250.126 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 a link on the MMS
Offshore Web site at: http://www.mms.gov/offshore/ homepage or directly
through Pay.gov at: https://www.pay.gov/paygov/.
(a) If you submitted an application through eWell, you must use the
interactive payment feature in that system, which directs you through
Pay.gov.
(b) For applications not submitted electronically through eWell, you
must use credit card or automated clearing house (ACH) payments through
the Pay.gov Web site, and you must include a copy of the Pay.gov
confirmation receipt page with your application.
[73 FR 49947, Aug. 25, 2008]
Inspection of Operations
Sec. 250.130 Why does MMS conduct inspections?
MMS 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 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 MMS notify me before conducting an inspection?
MMS conducts both scheduled and unscheduled inspections.
Sec. 250.132 What must I do when MMS conducts an inspection?
(a) When MMS 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
[[Page 71]]
(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.
Sec. 250.133 Will MMS reimburse me for my expenses related to inspections?
Upon request, MMS will reimburse you for food, quarters, and
transportation that you provide for MMS 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 MMS do if my operating performance is unacceptable?
If your operating performance is unacceptable, MMS 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 MMS officials before imposing a disqualification.
Sec. 250.136 How will MMS determine if my operating performance is unacceptable?
In determining if your operating performance is unacceptable, MMS
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 MMS 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 orally............. Give you an oral approval.. You must then confirm the oral request by
sending us a written request within 72
hours.
(b) Request approval in writing......... Give you an oral approval We will send you a written approval
if quick action is needed. afterward. It will include any
conditions that we place on the oral
approval.
(c) Request approval orally for gas Give you an oral approval.. You don't have to follow up with a
flaring. written 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 MMS 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 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.
[65 FR 6536, Feb. 10, 2000]
[[Page 72]]
Sec. 250.143 How do I designate an operator?
(a) You must provide the Regional Supervisor an executed Designation
of Operator form (Form MMS-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 service fee listed in Sec. 250.125 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 MMS in a single submittal, which is subject
to only one filing fee.
[64 FR 72775, Dec. 28, 1999, as amended at 70 FR 49876, Aug. 25, 2005;
72 FR 25200, May 4, 2007]
Sec. 250.144 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. 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 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, 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, 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 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
[[Page 73]]
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.
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.
[[Page 74]]
Right-of-use and Easement
Sec. 250.160 When will MMS grant me a right-of-use and easement, and what
requirements must I meet?
MMS 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 MMS.
(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 256.35 (Qualification
of lessees); establish a regional Company File as required by MMS; 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 MMS 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:
(1) You obtain a right-of-use and easement after January 12, 2004;
or
(2) You ask MMS 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 MMS as shown in the following
table:
------------------------------------------------------------------------
If... Then...
------------------------------------------------------------------------
(1) Your right-of-use and easement You must pay a rental of $5 per
site is located in water depths of acre per year with a minimum of
less than 200 meters; $450 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, 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 of acre per year with a minimum 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 218.54. If you fail to make a payment
that is late after written notice from MMS, MMS may initiate
cancellation of the right-of-use grant and easement.
[64 FR 72775, Dec. 28, 1999, as amended at 68 FR 69311, Dec. 12, 2003;
69 FR 29433, May 24, 2004; 72 FR 25200, May 4, 2007; 73 FR 49948, Aug.
25, 2008]
Sec. 250.161 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
[[Page 75]]
(d) A schedule for constructing any new facilities, drilling or
completing any wells, anticipated production rates, and productive life
of existing production facilities.
Sec. 250.162 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. 250.163 If I have a State lease, will MMS grant me a right-of-use and easement?
(a) MMS 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) MMS 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. 250.164 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 subject to MMS
regulations, 30 CFR parts 250 through 282, and any terms and conditions
that the Regional Director prescribes.
(b) For the whole or fraction of the first calendar year, and
annually after that, you must pay to MMS, in advance, an annual rental
payment.
Sec. 250.165 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. 250.125; and
(b) The first year's rental as specified in Sec. 250.160(g).
[53 FR 10690, Apr. 1, 1988. Redesignated at 63 FR 29479, May 29, 1998,
as amended at 72 FR 25200, May 4, 2007]
Sec. 250.166 If I have a State lease, what surety bond must I have for
a right-of-use and easement?
(a) Before MMS 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 256.54 (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.
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
[[Page 76]]
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.
[53 FR 10690, Apr. 1, 1988. Redesignated at 63 FR 29479, May 29, 1998,
as amended at 72 FR 25200, May 4, 2007]
Sec. 250.170 How long does a suspension last?
(a) MMS 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. MMS 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) MMS may terminate any suspension when the Regional Supervisor
determines the circumstances that justified the suspension no longer
exist or 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 MMS must receive the request before the end of the lease
term (i.e., end of primary term, end of the 180-day 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. Sec. 250.115, 250.116, or
250.1603 (SOP only);
(d) A commitment to production (SOP only); and
(e) The service fee listed in Sec. 250.125 of this subpart.
[70 FR 49876, Aug. 25, 2005]
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. MMS 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:
[[Page 77]]
(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;
(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) 5 years; or
(ii) 8 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
[[Page 78]]
(c)(2), (c)(3), and (c)(4)(i) and (ii) of this section.
[64 FR 72775, Dec. 28, 1999, as amended at 67 FR 44360, July 2, 2002; 70
FR 74663, Dec. 16, 2005; 72 FR 25200, May 4, 2007]
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 Sec. 218.154.
Sec. 250.177 What additional requirements may the Regional Supervisor order for a suspension?
If MMS 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) MMS 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
(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 250, 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 180 days of the
primary term, and whenever production resumes during the last 180 days
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 256). 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 180 days 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. Sec. 250.172, 250.173, 250.174, or 250.175 before the end of
the 180th day 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, 250.173, 250.174, or 250.175 before the end of the
180th day after you stop operations.
(e) You may ask the Regional Supervisor to allow you more than 180
days 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
[[Page 79]]
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 180-day period
after having ceased, or whenever drilling or well-reworking operations
begin before the end of the 180-day 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 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 180-day period.
Sec. 250.181 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 256, you are entitled to compensation under Sec. 250.184. Section
250.185 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. 250.182 When may the Secretary cancel a lease at the exploration stage?
MMS may not approve an exploration plan (EP) under 30 CFR part 250,
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. 250.183 When may MMS or the Secretary extend or cancel a lease at
the development and production stage?
(a) MMS may extend your lease if you submit a DPP and the Regional
[[Page 80]]
Supervisor disapproves the plan according to the regulations in 30 CFR
part 250, subpart B. Following the disapproval:
(1) MMS will allow you to hold the lease for 5 years, or less time
at your request;
(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 250, 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. 250.184 What is the amount of compensation for lease cancellation?
When the Secretary cancels a lease under Sec. Sec. 250.181, 250.182
or 250.183 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. 250.185 When is there no compensation for a lease cancellation?
You will not receive compensation from MMS for lease cancellation
if:
(a) MMS 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 250, 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 MMS 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. 250.186 What reporting information and report forms must I submit?
(a) You must submit information and reports as MMS 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 MMS's forms. You must arrange the data
on your form identical to the MMS form. If you generate your own form
and it omits terms and conditions contained on the official MMS form, we
will consider it to contain the omitted terms and conditions.
[[Page 81]]
(3) You may submit digital data when the Region/District is equipped
to accept it.
(b) When MMS 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.
[64 FR 72775, Dec. 28, 1999. Redesignated at 71 FR 19644, Apr. 17, 2006,
as amended at 72 FR 25200, May 4, 2007]
Sec. 250.187 What are MMS' 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 MMS, 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.
[71 FR 19644, Apr. 17, 2006]
Sec. 250.188 What incidents must I report to MMS 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 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
[[Page 82]]
in property or equipment damage greater than $25,000.
[71 FR 19644, Apr. 17, 2006]
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.
[71 FR 19644, Apr. 17, 2006]
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.);
(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.
[71 FR 19644, Apr. 17, 2006]
Sec. 250.191 How does MMS conduct incident investigations?
Any investigation that MMS 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 MMS. 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
[[Page 83]]
expenses must be similar to mileage and fees the U.S. District Courts
allow.
[71 FR 19645, Apr. 17, 2006]
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
MMS GOM OCS Region, use Form MMS-132) 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 MMS when you resume production; and
(4) Submit the statistics either by MMS district, or the total
figures for your operations in an MMS 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 MMS-143, Facility/Equipment Damage Report, to
make this and all subsequent reports. In lieu of submitting Form MMS-143
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).
(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.
[73 FR 64545, Oct. 30, 2008]
Sec. 250.193 Reports and investigations of apparent violations.
Any person may report to MMS an apparent violation or failure to
comply with any provision of the Act, any provision of a lease, license,
or permit issued under the Act, or any provision of any regulation or
order issued under the Act. When MMS receives a report of an apparent
violation, or when an MMS employee detects an apparent violation after
making an initial determination of the validity, MMS will investigate
according to MMS procedures.
Sec. 250.194 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
[[Page 84]]
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 Regional Director. If investigations determine that the resource is
significant, the Regional Director will tell you how to protect it.
[64 FR 72775, Dec. 28, 1999, as amended at 71 FR 23862, Apr. 25, 2006;
72 FR 25200, May 4, 2007]
Sec. 250.195 What notification does MMS require on the production status of wells?
You must notify the appropriate MMS 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);
(4) Type of production; and
(5) Measured depth of the production interval.
[71 FR 23862, Apr. 25, 2006]
Sec. 250.196 Reimbursements for reproduction and processing costs.
(a) MMS 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 MMS for the Regional Director to inspect or select and
retain;
(2) MMS 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) MMS 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 MMS 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) MMS will not reimburse you for data acquisition costs or for the
costs of analyzing or processing geological information or interpreting
geological or geophysical information.
[64 FR 72775, Dec. 28, 1999. Redesignated at 71 FR 23862, Apr. 25, 2006]
Sec. 250.197 Data and information to be made available to the public or for limited inspection.
MMS will protect data and information that you submit under this
part, and part 203 of 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.
(a) All data and information you submit on MMS forms will be made
available to the public upon submission, except as specified in the
following table:
[[Page 85]]
------------------------------------------------------------------------
Data and
information not
On form . . . immediately Excepted data will be
available are . . made available . . .
.
------------------------------------------------------------------------
(1) MMS-123, Application for Items 15, 16, 22 When the well goes on
Permit to Drill. through 25. production or
according to the
table in paragraph
(b) of this section,
whichever is
earlier.
(2) MMS-123S, Supplemental APD Items 3, 7, 8, 15 When the well goes on
Information Sheet. and 17. production or
according to the
table in paragraph
(b) of this section,
whichever is
earlier.
(3) MMS-124, Application for Item 17.......... When the well goes on
Permit to Modify. production or
according to the
table in paragraph
(b) of this section,
whichever is
earlier.
(4) MMS-125, End of Operations Items 12, 13, 17, When the well goes on
Report. 21, 22, 26 production or
through 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) MMS-126, Well Potential Item 101......... 2 years after you
Test Report. submit it.
(6) MMS-127, Sensitive Items 124 through 2 years after the
Reservoir Information Report. 168. effective date of
the Sensitive
Reservoir
Information Report.
(7) MMS-133 Well Activity Item 10 Fields When the well goes on
Report. [WELLBORE START production or
DATE, TD DATE, according to the
OP STATUS, END table in paragraph
DATE, MD, TVD, (b) of this section,
AND MW PPG]. whichever is
Item 11 Fields earlier.
[WELLBORE START
DATE, TD DATE,
PLUGBACK DATE,
FINAL MD, AND
FINAL TVD] and
Items 12 through
15.
(8) MMS-133S Open Hole Data Boxes 7 and 8.... When the well goes on
Report. production or
according to the
table in paragraph
(b) of this section,
whichever is
earlier.
(9) MMS-137 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) MMS-140, Bottomhole All items........ 2 years after the
Pressure Survey Report. date of the survey.
------------------------------------------------------------------------
(b) MMS will release lease and permit data and information that you
submit and MMS retains, but that are not normally submitted on MMS
forms, according to the following table:
----------------------------------------------------------------------------------------------------------------
If MMS will release At this time Special provisions
----------------------------------------------------------------------------------------------------------------
(1) The Director determines that Geophysical data, At any time........... MMS will release data and
data and information are needed Geological data information only if
for specific scientific or Interpreted G&G release would further the
research purposes for the information, national interest without
Government. Processed G&G unduly damaging the
information, Analyzed competitive position of
geological the lessee.
information.
(2) Data or information is Geophysical data, 60 days after MMS MMS will release the data
collected with high-resolution Geological data, receives the data or and information earlier
systems (e.g., bathymetry, side- Interpreted G&G information, if the than 60 days if the
scan sonar, subbottom profiler, information, Regional Supervisor Regional Supervisor
and magnetometer) to comply with Processed geological deems it necessary. determines it is needed by
safety or environmental protection information, Analyzed affected States to make
requirements. geological decisions under subpart B.
information. The Regional Supervisor
will reconsider earlier
release if you satisfy him/
her that it would unduly
damage your competitive
position.
(3) Your lease is no longer in Geophysical data, When your lease This release time applies
effect. Geological data, terminates. only if the provisions in
Processed G&G this table governing high-
information resolution systems and the
Interpreted G&G provisions in Sec. 252.7
information, Analyzed do not apply. The release
geological time applies to the
information. geophysical data and
information only if
acquired postlease for a
lessee's exclusive use.
[[Page 86]]
(4) Your lease is still in effect.. Geophysical data 10 years after you This release time applies
Processed geophysical submit the data and only if the provisions in
information, information. this table governing high-
Interpreted G&G resolution systems and the
information. provisions in Sec. 252.7
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 still in effect Geological data, 2 years after the These release times apply
and within the primary term Analyzed geological required submittal only if the provisions in
specified in the lease. information. date or 60 days after this table governing high-
a lease sale if any resolution systems and the
portion of an offered provisions in Sec. 252.7
lease is within 50 do not apply. If the
miles of a well, primary term specified in
whichever is later. the lease is extended
under the heading of
``Suspensions'' in this
subpart, the extension
applies to this provision.
(6) Your lease is in effect and Geological data, 2 years after the None.
beyond the primary term specified Analyzed geological required submittal
in the lease. information. date.
(7) Data or information is Descriptions of When the well goes on Directional survey data may
submitted on well operations. downhole locations, production or when be released earlier to the
operations, and geological data is owner of an adjacent lease
equipment. released according to according to Subpart D of
Sec. Sec. this part.
250.197(b)(5) and
(b)(6), whichever
occurs earlier.
(8) Data and information are Any data or At any time........... None.
obtained from beneath unleased information obtained.
land as a result of a well
deviation that has not been
approved by the District Manager
or Regional Supervisor.
(9) Except for high-resolution data G&G data, analyzed Geological data and None.
and information released under geological information: 10 years
paragraph (b)(2) of this section information, after MMS issues the
data and information acquired by a processed and permit; Geophysical
permit under part 251 are interpreted G&G data: 50 years after
submitted by a lessee under 30 CFR information. MMS issues the
part 203 or part 250. permit; Geophysical
information: 25 years
after MMS issues the
permit.
----------------------------------------------------------------------------------------------------------------
(c) MMS may allow limited inspection, but only by persons with a
direct interest in related MMS 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 part 203 of this
chapter that MMS 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) Make field determinations; or
(7) Determine eligibility for royalty relief.
[64 FR 72775, Dec. 28, 1999, as amended at 71 FR 16039, Mar. 30, 2006.
Redesignated and amended at 71 FR 23862, Apr. 25, 2006; 72 FR 25200, May
4, 2007]
References
Sec. 250.198 Documents incorporated by reference.
(a) The MMS 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
[[Page 87]]
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 MMS will
publish any changes to a document in the Federal Register and amend this
section.
(2) The MMS may make the rule amending the document effective
without prior opportunity for public comment when MMS 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 MMS 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 section 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. If any incorporated document uses the word should, it
means must for purposes of these regulations.
(b) The MMS 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 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 MMS official.
(d) You may inspect these documents at the Minerals Management
Service, 381 Elden Street, Room 3313, Herndon, Virginia 20170; phone:
703-787-1587; 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, P. O. Box
9094, Farmington Hill, MI 48333-9094: http://www.concrete.org; phone:
248-848-3700:
(1) ACI Standard 318-95, Building Code Requirements for Reinforced
Concrete (ACI 318-95) and Commentary (ACI 318R-95), incorporated by
reference at Sec. 250.901(a), (d).
(2) ACI 357R-84, Guide for the Design and Construction of Fixed
Offshore Concrete Structures, 1984; reapproved 1997, incorporated by
reference at Sec. 250.901(a), (d).
(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(a), (d).
(2) [Reserved]
(g) American National Standards Institute (ANSI), ANSI/ASME Codes,
ATTN: Sales Department, 25 West 43rd Street, 4th Floor, New York, NY
10036; http://www.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: 973-882-5155:
(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. 250.803(b)(1), (b)(1)(i); and Sec.
250.1629(b)(1), (b)(1)(i);
(2) ANSI/ASME Boiler and Pressure Vessel Code, Section IV, Rules for
Construction of Heating Boilers; including
[[Page 88]]
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. 250.803(b)(1), (b)(1)(i); and
Sec. 250.1629(b)(1), (b)(1)(i);
(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 and 2, and all Section VIII
Interpretations Volumes 54 and 55, incorporated by reference at Sec.
250.803(b)(1), (b)(1)(i); and Sec. 250.1629(b)(1), (b)(1)(i);
(4) ANSI/ASME B 16.5-2003, Pipe Flanges and Flanged Fittings
incorporated by reference at Sec. 250.1002(b)(2);
(5) ANSI/ASME B 31.8-2003, Gas Transmission and Distribution Piping
Systems incorporated by reference at Sec. 250.1002(a);
(6) ANSI/ASME SPPE-1-1994 and SPPE-1d-1996 Addenda, Quality
Assurance and Certification of Safety and Pollution Prevention Equipment
Used in Offshore Oil and Gas Operations, incorporated by reference at
Sec. 250.806(a)(2)(i);
(7) ANSI Z88.2-1992, American National Standard for Respiratory
Protection, incorporated by reference at, Sec. 250.490(g)(4)(iv),
(j)(13)(ii).
(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, Product No. C51009; incorporated by reference at Sec.
250.803(b)(1); and Sec. 250.1629(b)(1);
(2) API Bulletin 2INT-DG, Interim Guidance for Design of Offshore
Structures for Hurricane Conditions, May 2007, Product No. G2DGINT;
incorporated by reference at Sec. 250.901(a), (d);
(3) API Bulletin 2INT-EX, Interim Guidance for Assessment of
Existing Offshore Structures for Hurricane Conditions, May 2007, Product
No. G2EXINT; incorporated by reference at Sec. 250.901(a), (d);
(4) API Bulletin 2INT-MET, Interim Guidance on Hurricane Conditions
in the Gulf of Mexico, May 2007, Product No. G2INTMET; incorporated by
reference at Sec. 250.901(a), (d);
(5) API MPMS, Chapter 1--Vocabulary, Second Edition, July 1994,
Order No. 852-01002; 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, Order No. 852-022A1; incorporated by reference at Sec.
250.1202(l)(4);
(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, Order No. H30023;
incorporated by reference at Sec. 250.1202(l)(4);
(8) API MPMS, Chapter 3--Tank Gauging, Section 1A--Standard Practice
for the Manual Gauging of Petroleum and Petroleum Products, Second
Edition, August 2005, Product No. H301A02; incorporated by reference at
Sec. 250.1202(l)(4);
(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, Product No. H301B2; incorporated by reference at Sec.
250.1202(l)(4);
(10) API MPMS, Chapter 4--Proving Systems, Section 1--Introduction,
Third Edition, February 2005, Product No. H04013; incorporated by
reference at Sec. 250.1202(a)(3), (f)(1);
(11) API MPMS, Chapter 4--Proving Systems, Section 2--Displacement
Provers, Third Edition, September 2003, Product No. H04023; incorporated
by reference at Sec. 250.1202(a)(3), (f)(1);
(12) API MPMS, Chapter 4--Proving Systems, Section 4--Tank Provers,
Second Edition, May 1998, reaffirmed November 2005, Order No. H04042;
incorporated by reference at Sec. 250.1202(a)(3), (f)(1);
(13) API MPMS, Chapter 4--Proving Systems, Section 5--Master-Meter
[[Page 89]]
Provers, Second Edition, May 2000, reaffirmed: August 2005, Order No.
H04052; incorporated by reference at Sec. 250.1202(a)(3), (f)(1);
(14) API MPMS, Chapter 4--Proving Systems, Section 6--Pulse
Interpolation, Second Edition, May 1999; reaffirmed 2003, Order No.
H04062; incorporated by reference at Sec. 250.1202(a)(3), (f)(1);
(15) API MPMS, Chapter 4--Proving Systems, Section 7--Field Standard
Test Measures, Second Edition, December 1998; reaffirmed 2003, Order No.
H04072; incorporated by reference at Sec. 250.1202(a)(3), (f)(1);
(16) API MPMS, Chapter 5--Metering, Section 1--General
Considerations for Measurement by Meters, Fourth Edition, September
2005, Product No. H05014; incorporated by reference at Sec.
250.1202(a)(3);
(17) API MPMS, Chapter 5--Metering, Section 2--Measurement of Liquid
Hydrocarbons by Displacement Meters, Third Edition, September 2005,
Product No. H05023; incorporated by reference at Sec. 250.1202(a)(3);
(18) API MPMS Chapter 5--Metering, Section 3--Measurement of Liquid
Hydrocarbons by Turbine Meters, Fifth Edition, September 2005, Product
No. H05035; incorporated by reference at Sec. 250.1202(a)(3);
(19) API MPMS, Chapter 5--Metering, Section 4--Accessory Equipment
for Liquid Meters, Fourth Edition, September 2005, Product No. H05044;
incorporated by reference at Sec. 250.1202(a)(3);
(20) API MPMS, Chapter 5--Metering, Section 5--Fidelity and Security
of Flow Measurement Pulsed-Data Transmission Systems, Second Edition,
August 2005, Product No. H50502; incorporated by reference at Sec.
250.1202(a)(3);
(21) API MPMS, Chapter 6--Metering Assemblies, Section 1--Lease
Automatic Custody Transfer (LACT) Systems, Second Edition, May 1991;
reaffirmed, April 2007, Order No. H30121; incorporated by reference at
Sec. 250.1202(a)(3);
(22) API MPMS, Chapter 6--Metering Assemblies, Section 6--Pipeline
Metering Systems, Second Edition, May 1991; reaffirmed, February 2007,
Order No. 852-30126; incorporated by reference at Sec. 250.1202(a)(3);
(23) API MPMS, Chapter 6--Metering Assemblies, Section 7--Metering
Viscous Hydrocarbons, Second Edition, May 1991; reaffirmed, April 2007,
Order No. 852-30127; incorporated by reference at Sec. 250.1202(a)(3);
(24) API MPMS, Chapter 7--Temperature Determination, First Edition,
June 2001; reaffirmed, March 2007; Product No. H07001; incorporated by
reference at Sec. 250.1202(a)(3), (l)(4);
(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, Order No. H08013; incorporated by
reference at Sec. 250.1202(b)(4)(i), (l)(4);
(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 2005, Order No. H08022;
incorporated by reference at Sec. 250.1202(a)(3), (l)(4);
(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, Product
No. H09012; incorporated by reference at Sec. 250.1202(a)(3), (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, Product No. H09022;
incorporated by reference at Sec. 250.1202(a)(3), (l)(4);
(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, Product No. H10013; incorporated
by reference at Sec. 250.1202(a)(3), (l)(4);
(30) API MPMS, Chapter 10--Sediment and Water, Section 2--Standard
Test Method for Water in Crude Oil by Distillation, Second Edition,
November 2007, Product No. H10022; incorporated by reference at Sec.
250.1202(a)(3), (l)(4);
(31) API MPMS, Chapter 10--Sediment and Water, Section 3--Standard
Test Method for Water and Sediment in
[[Page 90]]
Crude Oil by the Centrifuge Method (Laboratory Procedure), Third
Edition, May 2008, Product No. H10033; incorporated by reference at
Sec. 250.1202(a)(3), (l)(4);
(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, Order No.
H10043; incorporated by reference at Sec. 250.1202(a)(3), (l)(4);
(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, Product No.
H10092; incorporated by reference at Sec. 250.1202(a)(3), (l)(4);
(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, API Stock No. H27000; incorporated by reference at Sec.
250.1202(a)(3), (g)(3), (l)(4);
(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, Order No. 852-27307; incorporated by
reference at Sec. 250.1202(a)(3), (g)(4);
(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, Order No. H27308; incorporated
by reference at Sec. 250.1202(a)(3);
(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, Order No. H12021; incorporated
by reference at Sec. 250.1202(a)(3), (g)(1), (g)(2);
(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, Product No. H12223; incorporated by reference
at Sec. 250.1202(a)(3), (g)(1), (g)(2);
(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, Order No. 852-30350; incorporated by reference at Sec.
250.1203(b)(2);
(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, Order No. H14324; incorporated by reference at Sec.
250.1203(b)(2);
(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, Product No. H143303; incorporated by reference at Sec.
250.1203(b)(2);
(42) API MPMS, Chapter 14.5/GPA Standard 2172-09; Calculation of
Gross Heating Value, Relative Density, Compressibility and Theoretical
Hydrocarbon Liquid Content for Natural Gas Mixtures for Custody
Transfer; Third Edition, January 2009; Adopted as Tentative Standard,
1972; Revised and Adopted as Standard, 1976; Revised 1984, 1986, 1996,
2009; Product No. H140503; incorporated by reference at Sec.
250.1203(b)(2);
(43) API MPMS, Chapter 14--Natural Gas Fluids Measurement, Section
6--Continuous Density Measurement, Second Edition, April 1991;
reaffirmed, February 2006, Order No. H30346; incorporated by reference
at Sec. 250.1203(b)(2);
(44) API MPMS, Chapter 14--Natural Gas Fluids Measurement, Section
8--Liquefied Petroleum Gas Measurement, Second Edition, July 1997;
reaffirmed, March 2006, Order No. H14082; incorporated by reference at
Sec. 250.1203(b)(2);
[[Page 91]]
(45) API MPMS, Chapter 20--Section 1--Allocation Measurement, First
Edition, September 1993; reaffirmed October 2006, Order No. 852-30701;
incorporated by reference at Sec. 250.1202(k)(1);
(46) API MPMS, Chapter 21--Flow Measurement Using Electronic
Metering Systems, Section 1--Electronic Gas Measurement, First Edition,
August 1993; reaffirmed, July 2005, Order No. 852-30730; incorporated by
reference at Sec. 250.1203(b)(4);
(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; Product No. G2AWSD; incorporated by reference at Sec.
250.901(a), (d); Sec. 250.908(a); Sec. 250.919(b)(2); Sec.
250.920(a), (b), (c), (d), (e), (f);
(48) API RP 2D, Operation and Maintenance of Offshore Cranes, Sixth
Edition, May 2007, Product No. G02D06; incorporated by reference at
Sec. 250.108(a);
(49) API RP 2FPS, RP for Planning, Designing, and Constructing
Floating Production Systems; First Edition, March 2001, Order No.
G2FPS1; incorporated by reference at Sec. 250.901(a), (d);
(50) API RP 2I, In-Service Inspection of Mooring Hardware for
Floating Structures; Third Edition, April 2008, Product No. G02I03;
incorporated by reference at Sec. 250.901(a), (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; Order
No. G02RD1; incorporated by reference at Sec. 250.800(b)(2); Sec.
250.901(a), (d); Sec. 250.1002(b)(5);
(52) API RP 2SK, Design and Analysis of Stationkeeping Systems for
Floating Structures, Third Edition, October 2005, Addendum, May 2008,
Product No. G2SK03; incorporated by reference at Sec. 250.800(b)(3);
Sec. 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, Product No.
G02SM1; incorporated by reference at Sec. 250.901(a), (d);
(54) API RP 2T, Recommended Practice for Planning, Designing, and
Constructing Tension Leg Platforms, Second Edition, August 1997, Order
No. G02T02; incorporated by reference at Sec. 250.901(a), (d);
(55) API RP 14B, Recommended Practice for Design, Installation,
Repair and Operation of Subsurface Safety Valve Systems, Fifth Edition,
October 2005, also available as ISO 10417: 2004, (Identical) Petroleum
and natural gas industries--Subsurface safety valve systems--Design,
installation, operation and redress, Product No. GX14B05; incorporated
by reference at Sec. 250.801(e)(4); Sec. 250.804(a)(1)(i);
(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; Product No. C14C07; incorporated by reference at Sec. 250.125(a);
Sec. 250.292(j); Sec. 250.802(b), (e)(2); Sec. 250.803(a), (b)(2)(i),
(b)(4), (b)(5)(i), (b)(7), (b)(9)(v), (c)(2); Sec. 250.804(a), (a)(6);
Sec. 250.1002(d); Sec. 250.1004(b)(9); Sec. 250.1628(c), (d)(2);
Sec. 250.1629(b)(2), (b)(4)(v); Sec. 250.1630(a);
(57) API RP 14E, Recommended Practice for Design and Installation of
Offshore Production Platform Piping Systems, Fifth Edition, October
1991; reaffirmed, March 2007, Order No. 811-07185; incorporated by
reference at Sec. 250.802(e)(3); Sec. 250.1628(b)(2), (d)(3);
(58) API RP 14F, Design, Installation, and Maintenance of Electrical
Systems for Fixed and Floating Offshore Petroleum Facilities for
Unclassified and Class I, Division 1 and Division 2 Locations, Fifth
Edition, July 2008, Product No. G14F05; incorporated by reference at
Sec. 250.114(c); Sec. 250.803(b)(9)(v); Sec. 250.1629(b)(4)(v);
(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;
Product No. G14FZ1; incorporated by reference at Sec. 250.114(c); Sec.
250.803(b)(9)(v); Sec. 250.1629(b)(4)(v);
[[Page 92]]
(60) API RP 14G, Recommended Practice for Fire Prevention and
Control on Fixed Open-type Offshore Production Platforms, Fourth
Edition, April 2007; Product No. G14G04; incorporated by reference at
Sec. 250.803(b)(8), (b)(9)(v); Sec. 250.1629(b)(3), (b)(4)(v);
(61) API RP 14H, Recommended Practice for Installation, Maintenance
and Repair of Surface Safety Valves and Underwater Safety Valves
Offshore, Fifth Edition, August 2007, Product No. G14H05; incorporated
by reference at Sec. 250.802(d); Sec. 250.804(a)(5);
(62) API RP 14J, Recommended Practice for Design and Hazards
Analysis for Offshore Production Facilities, Second Edition, May 2001;
reaffirmed: March 2007; Product No. G14J02; incorporated by reference at
Sec. 250.800(b)(1); Sec. 250.901(a)(14);
(63) API RP 53, Recommended Practices for Blowout Prevention
Equipment Systems for Drilling Wells, Third Edition, March 1997;
reaffirmed September 2004, Order No. G53003; incorporated by reference
at Sec. 250.442(c); Sec. 250.446(a); Sec. 250.516(g)(1); Sec.
250.516(h); and Sec. 250.617(a)(1), and (b);
(64) API RP 65, Recommended Practice for Cementing Shallow Water
Flow Zones in Deepwater Wells, First Edition, September 2002, Product
No. G56001; incorporated by reference at Sec. 250.415(e);
(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; reaffirmed November 2002, Product No. C50002;
incorporated by reference at Sec. 250.114(a); Sec. 250.459; Sec.
250.802(e)(4)(i); Sec. 250.803(b)(9)(i); Sec. 250.1628(b)(3),
(d)(4)(i); Sec. 250.1629(b)(4)(i);
(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 November 2002, Order No. C50501; incorporated
by reference at Sec. 250.114(a); Sec. 250.459; Sec. 250.802(e)(4)(i);
Sec. 250.803(b)(9)(i); Sec. 250.1628(b)(3), (d)(4)(i); Sec.
250.1629(b)(4)(i);
(67) API RP 2556, Recommended Practice for Correcting Gauge Tables
for Incrustation, Second Edition, August 1993; reaffirmed November 2003,
Order No. H25560; incorporated by reference at Sec. 250.1202(l)(4);
(68) ANSI/API Spec. Q1, Specification for Quality Programs for the
Petroleum, Petrochemical and Natural Gas Industry, ISO TS 29001:2007
(Identical), Petroleum, petrochemical and natural gas industries--Sector
specific requirements--Requirements for product and service supply
organizations, Eighth Edition, December 2007, Effective Date: June 15,
2008, Product No. GXQ108; incorporated by reference at Sec.
250.806(a)(2)(ii);
(69) API Spec. 2C, Specification for Offshore Pedestal Mounted
Cranes, Sixth Edition, March 2004, Effective Date: September 2004,
Product No. G02C06; incorporated by reference at Sec. 250.108(c), (d);
(70) ANSI/API Spec. 6A, Specification for Wellhead and Christmas
Tree Equipment, Nineteenth Edition, July 2004; Effective Date: February
1, 2005; Contains API Monogram Annex as Part of U.S. National Adoption;
ISO 10423:2003 (Modified), Petroleum and natural gas industries--
Drilling and production equipment--Wellhead and Christmas tree
equipment; Errata 1, September 2004, Errata 2, April 2005, Errata 3,
June 2006, Errata 4, August 2007, Errata 5, May 2009; Addendum 1,
February 2008; Addendum 2, 3, and 4, December 2008; Product No. GX06A19;
incorporated by reference at Sec. 250.806(a)(3); Sec. 250.1002(b)(1),
(b)(2);
(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 January 2003, Order No.
G06AV1; incorporated by reference at Sec. 250.806(a)(3);
(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; Product
No. GX6D23; incorporated by reference at Sec. 250.1002(b)(1);
[[Page 93]]
(73) ANSI/API Spec. 14A, Specification for Subsurface Safety Valve
Equipment, Eleventh Edition, October 2005, Effective Date: May 1, 2006;
also available as ISO 10432:2004, Product No. GX14A11; incorporated by
reference at Sec. 250.806(a)(3);
(74) ANSI/API Spec. 17J, Specification for Unbonded Flexible Pipe,
Third Edition, July 2008; Effective Date: January 1, 2009, Contains API
Monogram Annex as Part of U.S. National Adoption; ISO 13628-2:2006
(Identical), Petroleum and natural gas industries--Design and operation
of subsea production systems--Part 2: Unbonded flexible pipe systems for
subsea and marine application; Product No. GX17J03; incorporated by
reference at Sec. 250.803(b)(2)(iii); Sec. 250.1002(b)(4); Sec.
250.1007(a)(4);
(75) API Standard 2551, Measurement and Calibration of Horizontal
Tanks, First Edition, 1965; reaffirmed March 2002, API Stock No. H25510;
incorporated by reference at Sec. 250.1202(l)(4);
(76) API Standard 2552, USA Standard Method for Measurement and
Calibration of Spheres and Spheroids, First Edition, 1966; reaffirmed,
October 2007 (ASTM designation: D 1408-65; date of joint API/ASTM
approval, 1965); incorporated by reference at Sec. 250.1202(l)(4);
(77) API Standard 2555, Method for Liquid Calibration of Tanks,
First Edition, September 1966; reaffirmed March 2002; Order No. 852-
25550; incorporated by reference at Sec. 250.1202(l)(4).
(78) API RP 90, Annular Casing Pressure Management for Offshore
Wells, First Edition, August 2006, Product No. G09001, incorporated by
reference at Sec. 250.518.
(79) API RP 65-Part 2, Isolating Potential Flow Zones During Well
Construction; First Edition, May 2010; Product No. G65201; incorporated
by reference at Sec. 250.415(f).
(80) 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, Product No. G07503;
incorporated by reference at Sec. Sec. 250.1900, 250.1900(c),
250.1902(c), 250.1903, 250.1909, 250.1920(a) and (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: 610-832-9500:
(1) ASTM Standard C 33-07, approved December 15, 2007, Standard
Specification for Concrete Aggregates; incorporated by reference at
Sec. 250.901(a), (d);
(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(a), (d);
(3) ASTM Standard C 150-07, approved May 1, 2007, Standard
Specification for Portland Cement; incorporated by reference at Sec.
250.901(a), (d);
(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(a), (d);
(5) ASTM Standard C 595-08, approved January 1, 2008, Standard
Specification for Blended Hydraulic Cements; incorporated by reference
at Sec. 250.901(a), (d);
(j) American Welding Society (AWS), AWS Codes, 550 NW, LeJeune Road,
Miami, FL 33126; http://www.aws.org; phone: 800-443-9353:
(1) AWS D1.1:2000, Structural Welding Code--Steel; incorporated by
reference at Sec. 250.901(a), (d);
(2) AWS D1.4-98, Structural Welding Code--Reinforcing Steel;
incorporated by reference at Sec. 250.901(a), (d);
(3) AWS D3.6M:1999, Specification for Underwater Welding;
incorporated by reference at Sec. 250.901(a), (d).
(k) National Association of Corrosion Engineers (NACE), NACE
Standards, 1440 South Creek Drive, Houston, TX 77084; http://
www.nace.org; phone: 281-228-6200:
(1) NACE Standard MR0175-2003, Item No. 21302, Standard Material
Requirements, Metals for Sulfide Stress Cracking and Stress Corrosion
Cracking Resistance in Sour Oilfield Environments; incorporated by
reference at Sec. 250.901(a), Sec. 250.490(p)(2);
(2) NACE Standard RP0176-2003, Item No. 21018, Standard Recommended
Practice, Corrosion Control of Steel Fixed Offshore Structures
Associated with Petroleum Production; incorporated by reference at Sec.
250.901(a), (d).
[75 FR 22222, Apr. 28, 2010, as amended at 75 FR 23584, May 4, 2010; 75
FR 63372, Oct. 14, 2010; 75 FR 63649, Oct. 15, 2010]
[[Page 94]]
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 MMS uses the information. The
associated MMS 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; parts 251 and 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, Minerals
Management Service, Mail Stop 5438, 1849 C Street, NW., Washington, DC
20240.
(e) MMS is collecting this information for the reasons given in the
following table:
------------------------------------------------------------------------
30 CFR subpart, title and/or MMS Form Reasons for collecting
(OMB Control No.) information and how used
------------------------------------------------------------------------
(1) Subpart A, General (1010-0114), To inform MMS of actions taken
including Forms MMS-132, Evacuation to comply with general
Statistics; MMS-143, Facility/ operational requirements on
Equipment Damage Report; MMS-1123, the OCS. To ensure that
Designation of Operator; MMS-1832, operations on the OCS meet
Notification of Incidents of statutory and regulatory
Noncompliance. 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.
To allow MMS to rapidly assess
damage and project any
disruption of oil and gas
production from the OCS after
a major natural occurrence.
(2) Subpart B, Exploration and To inform MMS, States, and the
Development and Production Plans (1010- public of planned exploration,
0151), including Forms MMS-137, OCS development, and production
Plan Information Form; MMS-139, EP Air operations on the OCS. To
Quality Screening Checklist; MMS-138, ensure that operations on the
DOCD Air Quality Screening Checklist, OCS are planned to comply with
MMS-141, ROV Survey Report Form; MMS- statutory and regulatory
142, Environmental Impact Analysis requirements, will be safe and
Worksheet. protect the human, marine, and
coastal environment, and will
result in diligent
exploration, development, and
production of leases.
(3) Subpart C, Pollution Prevention and To inform MMS of measures to be
Control (1010-0057). taken to prevent water and air
pollution. To ensure that
appropriate measures are taken
to prevent water and air
pollution.
(4) Subpart D, Oil and Gas and Drilling To inform MMS of the equipment
Operations (1010-0141), including and procedures to be used in
Forms MMS-123, Application for Permit drilling operations on the
to Drill; MMS-123S, Supplemental APD OCS. To ensure that drilling
Information Sheet; MMS-124, operations are safe and
Application for Permit to Modify; MMS- protect the human, marine, and
125, End of Operations Report; MMS- coastal environment.
133, Well Activity Report; MMS-133S,
Open Hole Data Report.
(5) Subpart E, Oil and Gas Well- To inform MMS of the equipment
Completion Operations (1010-0067). and procedures to be used in
well-completion operations on
the OCS. To ensure that well-
completion operations are safe
and protect the human, marine,
and coastal environment.
(6) Subpart F, Oil and Gas Well To inform MMS of the equipment
Workover Operations (1010-0043). and procedures to be used
during well-workover
operations on the OCS. To
ensure that well-workover
operations are safe and
protect the human, marine, and
coastal environment.
(7) Subpart H, Oil and Gas Production To inform MMS of the equipment
Safety Systems (1010-0059). and procedures to be used
during production operations
on the OCS. To ensure that
production operations are safe
and protect the human, marine,
and coastal environment.
(8) Subpart I, Platforms and Structures To provide MMS with information
(1010-0149). regarding the design,
fabrication, and installation
of platforms on the OCS. To
ensure the structural
integrity of platforms
installed on the OCS.
[[Page 95]]
(9) Subpart J, Pipelines and Pipeline To provide MMS with information
Rights-of-Way (1010-0050). regarding the design,
installation, and operation of
pipelines on the OCS. To
ensure that pipeline
operations are safe and
protect the human, marine, and
coastal environment.
(10) Subpart K, Oil and Gas Production To inform MMS of production
Rates (1010-0041), including Forms MMS- rates for hydrocarbons
126, Well Potential Test Report; MMS- produced on the OCS. To ensure
127, Sensitive Reservoir Information economic maximization of
Report; MMS-128, Semiannual Well Test ultimate hydrocarbon recovery.
Report; MMS-140 Bottomhole Pressure
Survey Report.
(11) Subpart L, Oil and Gas Production To inform MMS of the
Measurement, Surface Commingling, and measurement of production,
Security (1010-0051). commingling of hydrocarbons,
and site security plans. To
ensure that produced
hydrocarbons are measured and
commingled to provide for
accurate royalty payments and
security is maintained.
(12) Subpart M, Unitization (1010-0068) To inform MMS of the
unitization of leases. To
ensure that unitization
prevents waste, conserves
natural resources, and
protects correlative rights.
(13) 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.
(14) Subpart O, Well Control and To inform MMS of training
Production Safety Training (1010-0128). program curricula, course
schedules, and attendance. To
ensure that training programs
are technically accurate and
sufficient to meet safety and
environmental requirements,
and that workers are properly
trained to operate on the OCS.
(15) Subpart P, Sulphur Operations To inform MMS of sulphur
(1010-0086). exploration and development
operations on the OCS. To
ensure that OCS sulphur
operations are safe; protect
the human, marine, and coastal
environment; and will result
in diligent exploration,
development, and production of
sulphur leases.
(16) Subpart Q, Decommissioning To determine that
Activities (1010-0142). 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.
(17) Subpart S, Safety and The SEMS program will describe
Environmental Management Systems (1010- management commitment to
0186), including Form MMS-131, safety and the environment, as
Performance Measures Data. well as policies and
procedures to assure safety
and environmental protection
while conducting OCS
operations (including those
operations conducted by
contractor and subcontractor
personnel). The information
collected is the form to
gather the raw Performance
Measures Data relating to risk
and number of accidents,
injuries, and oil spills
during OCS activities.
(18) Form MMS-144, Rig Movement The rig notification
Notification Report (form used in the requirement is essential for
GOM OCS Region), Subparts D, E, F, MMS inspection scheduling and
(1010-0150). to verify that the equipment
being used complies with
approved permits.
------------------------------------------------------------------------
[64 FR 72775, Dec. 28, 1999, as amended at 67 FR 35405, May 17, 2002; 68
FR 8422, Feb. 20, 2003; 71 FR 23863, Apr. 25, 2006; 72 FR 25200, May 4,
2007; 73 FR 64546, Oct. 30, 2008; 74 FR 46908, Sept. 14, 2009; 75 FR
20289, Apr. 19, 2010; 75 FR 63649, Oct. 15, 2010]
Subpart B_Plans and Information
Source: 70 FR 51501, Aug. 30, 2005, unless otherwise noted.
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:
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
MMS means Minerals Management Service
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 96]]
Amendment means a change you make to an EP, DPP, or DOCD that is
pending before MMS for a decision (see Sec. Sec. 250.232(d) and
250.267(d)).
Modification means a change required by the Regional Supervisor to
an EP, DPP, or DOCD (see Sec. 250.233(b)(2) and Sec. 250.270(b)(2))
that is pending before MMS 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 an MMS 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 MMS has disapproved (see Sec. Sec.
250.234(b), 250.272(a), and 250.273(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. 250.283(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. 250.283(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 MMS
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 (DOCD). activities on a lease or unit in the
Western GOM.
(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) 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.
250.105) 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. 250.209,
determines that an EP, DPP, or DOCD is
necessary.
------------------------------------------------------------------------
(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:
[[Page 97]]
(1) Sufficient applicable information or analysis is readily
available to MMS;
(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 MMS.
[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 25200, May 4, 2007]
Sec. 250.202 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. 250.203 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. 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.
Sec. 250.206 How do I submit the EP, DPP, or DOCD?
(a) Number of copies. When you submit an EP, DPP, or DOCD to MMS,
you must provide:
[[Page 98]]
(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 EP, DPP, or DOCD by certain affected States and other reviewing
entities.
(b) Electronic submission. You may submit part or all of your EP,
DPP, or DOCD and its accompanying information electronically. If you
prefer to submit your EP, DPP, or DOCD electronically, ask the Regional
Supervisor for further guidance.
(c) Withdrawal after submission. You may withdraw your proposed EP,
DPP, or DOCD at any time for any reason. Notify the appropriate MMS OCS
Region if you do.
Ancillary Activities
Sec. 250.207 What ancillary activities may I conduct?
Before or after you submit an EP, DPP, or DOCD to MMS, 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. 250.208 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. 250.207(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
(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 MMS at least 15 calendar days before you
conduct any other ancillary activity (see Sec. 250.207(b) and (c)) in
addition to those listed in Sec. 250.207(a); and
(2) Notify other users of the OCS before you conduct any ancillary
activity.
Sec. 250.209 What is the MMS review process for the notice?
The Regional Supervisor will review any notice required under Sec.
250.208(a) and (b)(1) to ensure that your ancillary activity complies
with the performance standards listed in Sec. 250.202(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. 250.210 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, MMS
will protect and disclose the data and information in these reports in
accordance with Sec. 250.197(b).
[[Page 99]]
(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. 250.207(a)), including any such data and information you obtained
from previous leaseholders or unit operators. You must submit such data
and information to MMS for inspection and possible retention upon
request at any time before lease or unit termination. When applicable,
MMS will protect and disclose such submitted data and information in
accordance with Sec. 250.197(b).
[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 25200, May 4, 2007]
Contents of Exploration Plans (EP)
Sec. 250.211 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 third definition of ``facility'' under Sec. 250.105).
(d) Service fee. You must include payment of the service fee listed
in Sec. 250.125.
[70 FR 51501, Aug. 30, 2005, as amended at 71 FR 40911, July 19, 2006]
Sec. 250.212 What information must accompany the EP?
The following information must accompany your EP:
(a) General information required by Sec. 250.213;
(b) Geological and geophysical (G&G) information required by Sec.
250.214;
(c) Hydrogen sulfide information required by Sec. 250.215;
(d) Biological, physical, and socioeconomic information required by
Sec. 250.216;
(e) Solid and liquid wastes and discharges information and cooling
water intake information required by Sec. 250.217;
(f) Air emissions information required by Sec. 250.218;
(g) Oil and hazardous substance spills information required by Sec.
250.219;
(h) Alaska planning information required by Sec. 250.220;
(i) Environmental monitoring information required by Sec. 250.221;
(j) Lease stipulations information required by Sec. 250.222;
(k) Mitigation measures information required by Sec. 250.223;
(l) Support vessels and aircraft information required by Sec.
250.224;
(m) Onshore support facilities information required by Sec.
250.225;
(n) Coastal zone management information required by Sec. 250.226;
(o) Environmental impact analysis information required by Sec.
250.227; and
(p) Administrative information required by Sec. 250.228.
Sec. 250.213 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
[[Page 100]]
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. 250.200) 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 256, subpart I;
(2) You have demonstrated or will demonstrate oil spill financial
responsibility for facilities proposed in your EP according to 30 CFR
part 253; 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. 250.214 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 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
[[Page 101]]
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. 250.215 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 Sec. 250.490(c), a request that the
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 Sec. 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. 250.216 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 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. 250.194).
(c) Socioeconomic study reports. Socioeconomic information regarding
your proposed exploration activities.
[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 18584, Apr. 13, 2007]
Sec. 250.217 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:
[[Page 102]]
(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. 250.218 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.
(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. 250.303 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
[[Page 103]]
amounts ``E'' calculated using the formulas in Sec. 250.303(d). When
MMS 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. 250.303 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. 250.219 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. 250.220 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 blowout, loss or disablement of a drilling unit, and loss
of or damage to support craft.
(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.
Sec. 250.221 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
[[Page 104]]
oil spill on the environmentally sensitive resources at the FGBNMS.
[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 18584, Apr. 13, 2007]
Sec. 250.222 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. 250.223 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.
[72 FR 18585, Apr. 13, 2007]
Sec. 250.224 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. 250.213(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.
250.217(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. 250.225 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.
[[Page 105]]
(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
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. 250.217) and the types and
quantities of such wastes.
Sec. 250.226 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. 250.227 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
[[Page 106]]
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.
(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.
[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 18585, Apr. 13, 2007]
Sec. 250.228 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. 250.231 After receiving the EP, what will MMS 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. 250.212), fulfills
requirements and is sufficiently accurate;
(2) You have provided all needed additional information (see Sec.
250.201(b)); and
(3) You have provided the required number of copies (see Sec.
250.206(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. 250.232 What actions will MMS take after the EP is deemed submitted?
(a) State and CZMA consistency reviews. Within 2 working days after
deeming your EP submitted under Sec. 250.231, 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) MMS 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. 250.202.
(c) MMS environmental impact evaluation. The Regional Supervisor
will evaluate the environmental impacts of
[[Page 107]]
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 amended, is subject to the requirements of Sec. 250.231.
[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 25200, May 4, 2007]
Sec. 250.233 What decisions will MMS 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.
250.231, or receives the last amendment to your proposed EP, whichever
occurs later.
(b) MMS 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 The Regional
applicable Supervisor will
requirements. 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 The Regional
your proposed EP. Supervisor finds Supervisor will
that it is notify you in
inconsistent with writing of the
the lease, the Act, decision and
the regulations describe the
prescribed under modifications you
the Act, or other must make to your
Federal laws. proposed EP to
ensure it complies
with all applicable
requirements.
(3) Disapprove your EP...... Your proposed (i) The Regional
activities would Supervisor will
probably cause notify you in
serious harm or writing of the
damage to life decision and
(including fish or describe the
other aquatic reason(s) for
life); property; disapproving your
any mineral (in EP.
areas leased or not (ii) MMS may cancel
leased); the your lease and
national security compensate you
or defense; or the under 43 U.S.C.
marine, coastal, or 1334(a)(2)(C) and
human environment; the implementing
and you cannot regulations in Sec.
modify your Sec. 250.182,
proposed activities 250.184, and
to avoid such 250.185 and 30 CFR
condition(s). 256.77.
------------------------------------------------------------------------
[70 FR 51501, Aug. 30, 2005, as amended at 74 FR 46908, Sept. 14, 2009]
Sec. 250.234 How do I submit a modified EP or resubmit a disapproved EP, and when will MMS make a decision?
(a) Modified EP. If the Regional Supervisor requires you to modify
your proposed EP under Sec. 250.233(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. 250.233(b)(3), you may resubmit the disapproved EP if there
is a change in the conditions that were the basis of its disapproval.
(c) MMS review and timeframe. The Regional Supervisor will use the
performance standards in Sec. 250.202 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. 250.235 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. 250.233(a) or Sec. 250.234(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
[[Page 108]]
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.
(c) Withdraw your EP. Withdraw your EP if you decide not to conduct
your proposed exploration activities.
[70 FR 51501, Aug. 30, 2005; 71 FR 12438, Mar. 10, 2006]
Contents of Development and Production Plans (DPP) and Development
Operations Coordination Documents (DOCD)
Sec. 250.241 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. 250.105); 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 third definition of ``facility'' under Sec. 250.105).
(d) Production facilities. A description of the production
platforms, satellite structures, subsea wellheads and manifolds, lease
term pipelines (see definition at Sec. 250.105), 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 third definition of
``facility'' under Sec. 250.105).
(e) Service fee. You must include payment of the service fee listed
in Sec. 250.125.
[70 FR 51501, Aug. 30, 2005, as amended at 71 FR 40911, July 19, 2006]
Sec. 250.242 What information must accompany the DPP or DOCD?
The following information must accompany your DPP or DOCD.
(a) General information required by Sec. 250.243;
(b) G&G information required by Sec. 250.244;
(c) Hydrogen sulfide information required by Sec. 250.245;
(d) Mineral resource conservation information required by Sec.
250.246;
(e) Biological, physical, and socioeconomic information required by
Sec. 250.247;
(f) Solid and liquid wastes and discharges information and cooling
water intake information required by Sec. 250.248;
(g) Air emissions information required by Sec. 250.249;
(h) Oil and hazardous substance spills information required by Sec.
250.250;
(i) Alaska planning information required by Sec. 250.251;
[[Page 109]]
(j) Environmental monitoring information required by Sec. 250.252;
(k) Lease stipulations information required by Sec. 250.253;
(l) Mitigation measures information required by Sec. 250.254;
(m) Decommissioning information required by Sec. 250.255;
(n) Related facilities and operations information required by Sec.
250.256;
(o) Support vessels and aircraft information required by Sec.
250.257;
(p) Onshore support facilities information required by Sec.
250.258;
(q) Sulphur operations information required by Sec. 250.259;
(r) Coastal zone management information required by Sec. 250.260;
(s) Environmental impact analysis information required by Sec.
250.261; and
(t) Administrative information required by Sec. 250.262.
Sec. 250.243 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. 250.200) 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 256, 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 253; 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.
[[Page 110]]
(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. 250.244 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 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. 250.245 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 Sec. 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) H2S 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 Sec.
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
[[Page 111]]
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
methodologies outlined in 40 CFR part 68.
Sec. 250.246 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. 250.247 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. 250.194).
(c) Socioeconomic study reports. Socioeconomic information related
to your proposed development and production activities.
[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 18585, Apr. 13, 2007]
Sec. 250.248 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
[[Page 112]]
(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.
(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. 250.249 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.
[[Page 113]]
(e) Non-exempt facilities. A description of how you will comply with
Sec. 250.303 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.
250.303(d). When MMS 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. 250.303 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.
Sec. 250.250 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. 250.251 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. 250.252 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
[[Page 114]]
(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 an oil spill on the environmentally sensitive
resources of the FGBNMS.
[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 18585, Apr. 13, 2007]
Sec. 250.253 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 your proposed development
and production activities must accompany your DPP or DOCD.
Sec. 250.254 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.
[72 FR 18585, Apr. 13, 2007]
Sec. 250.255 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. 250.256 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. 250.257 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
[[Page 115]]
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. 250.243(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 of the composition,
quantities, and destination(s) of solid and liquid wastes (see Sec.
250.248(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. 250.258 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. 250.248(a))
and the types and quantities of such wastes.
Sec. 250.259 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.
[[Page 116]]
Sec. 250.260 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).
[70 FR 51501, Aug. 30, 2005, as amended at 73 FR 20171, Apr. 15, 2008]
Sec. 250.261 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:
(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.
[[Page 117]]
(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.
[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 18585, Apr. 13, 2007]
Sec. 250.262 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
(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. 250.266 After receiving the DPP or DOCD, what will MMS 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. 250.242), fulfills
requirements and is sufficiently accurate;
(2) You have provided all needed additional information (see Sec.
250.201(b)); and
(3) You have provided the required number of copies (see Sec.
250.206(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. 250.267 What actions will MMS 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. 250.266, 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
[[Page 118]]
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. 250.266, 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
MMS 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) MMS 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. 250.202.
(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 or DOCD, the Regional
Supervisor may determine that your DPP or DOCD, as amended, is subject
to the requirements of Sec. 250.266.
Sec. 250.268 How does MMS 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. 250.269 How will MMS 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 MMS 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 MMS
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. 250.270 What decisions will MMS 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:
[[Page 119]]
(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. 250.267(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, MMS 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) MMS 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 DPP or DOCD It complies with all The Regional
applicable Supervisor will
requirements. 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 It fails to make The Regional
your proposed DPP or DOCD. adequate provisions Supervisor will
for safety, notify you in
environmental writing of the
protection, or decision and
conservation of describe the
natural resources modifications you
or otherwise does must make to your
not comply with the proposed DPP or
lease, the Act, the DOCD to ensure it
regulations complies with all
prescribed under applicable
the Act, or other requirements.
Federal laws.
(3) Disapprove your DPP or Any of the reasons (i) The Regional
DOCD. in Sec. 250.271 Supervisor will
apply. notify you in
writing of the
decision and
describe the
reason(s) for
disapproving your
DPP or DOCD; and
(ii) MMS may cancel
your lease and
compensate you
under 43 U.S.C.
1351(h)(2)(C) and
the implementing
regulations in Sec.
Sec. 250.183,
250.184, and
250.185 and 30 CFR
256.77.
------------------------------------------------------------------------
[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 18585, Apr. 13, 2007]
Sec. 250.271 For what reasons will MMS 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
[[Page 120]]
interest of national security. In that event, you do not need to
resubmit your DPP or DOCD for approval under Sec. 250.273(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. 250.272 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 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. 250.273 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. 250.270(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. 250.270(b)(3), and except as provided in
Sec. 250.271(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) MMS review and timeframe. The Regional Supervisor will use the
performance standards in Sec. 250.202 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. 250.280 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 MMS enforcement action, including civil
penalties; and
[[Page 121]]
(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. 250.185(b) and 30 CFR
256.77.
(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. 250.281 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 Regional
Supervisor:
(1) Approval of applications for permits to drill (APDs) (see Sec.
250.410);
(2) Approval of production safety systems (see Sec. 250.800);
(3) Approval of new platforms and other structures (or major
modifications to platforms and other structures) (see Sec. 250.905);
(4) Approval of applications to install lease term pipelines (see
Sec. 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 District Manager or 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 MMS 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.
[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 25200, May 4, 2007]
Sec. 250.282 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 MMS 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
[[Page 122]]
specify requirements for preparing and submitting these reports.
[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 18585, Apr. 13, 2007]
Sec. 250.283 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
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. 250.284 How will MMS 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. 250.285 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. 250.231 through Sec. 250.235 for EPs and Sec. 250.266 through
Sec. 250.273 for DPPs and DOCDs.
[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 25201, May 4, 2007]
Deepwater Operations Plans (DWOP)
Sec. 250.286 What is a DWOP?
(a) A DWOP is a plan that provides sufficient information for MMS 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 Exploration Plans,
Development and Production Plans, and Development Operations
Coordination Documents. MMS
[[Page 123]]
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 MMS 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
MMS 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 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;
[[Page 124]]
(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; and
(p) Payment of the service fee listed in Sec. 250.125.
[70 FR 51501, Aug. 30, 2005, as amended at 71 FR 40911, July 19, 2006]
Sec. 250.293 What operations require approval of the DWOP?
You may not begin production until MMS 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.
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.
Conservation Information Documents (CID)
Sec. 250.296 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. 250.125.
(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.
[70 FR 51501, Aug. 30, 2005, as amended at 71 FR 40911, July 19, 2006]