[Federal Register Volume 76, Number 201 (Tuesday, October 18, 2011)]
[Rules and Regulations]
[Pages 64431-64780]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2011-22675]



[[Page 64431]]

Vol. 76

Tuesday,

No. 201

October 18, 2011

Part II





Department of the Interior





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Bureau of Safety and Environmental Enforcement





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30 CFR Chapter II





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Bureau of Ocean Energy Management





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30 CFR Chapter V





Reorganization of Title 30: Bureaus of Safety and Environmental 
Enforcement and Ocean Energy Management; Final Rule

Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / 
Rules and Regulations

[[Page 64432]]


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DEPARTMENT OF THE INTERIOR

Bureau of Safety and Environmental Enforcement

30 CFR Chapter II

Bureau of Ocean Energy Management

30 CFR Chapter V

[Docket ID: BOEM-2011-0070]
RIN 1010-AD79


Reorganization of Title 30: Bureaus of Safety and Environmental 
Enforcement and Ocean Energy Management

AGENCY: Bureau of Safety and Environmental Enforcement (BSEE); 
Interior, Bureau of Ocean Energy Management (BOEM); Interior.

ACTION: Direct final rule.

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

SUMMARY: This rule contains regulations that will be under the 
authority of two newly formed Bureaus, the Bureau of Safety and 
Environmental Enforcement (BSEE) and the Bureau of Ocean Energy 
Management (BOEM), both within the Department of the Interior. On May 
19, 2010, the Secretary of the Interior announced the separation of the 
responsibilities performed by the Bureau of Ocean Energy Management, 
Regulation and Enforcement (BOEMRE) (formerly the Minerals Management 
Service) into three new separate organizations: Office of Natural 
Resources Revenue (ONRR), Bureau of Ocean Energy Management (BOEM), and 
Bureau of Safety and Environmental Enforcement (BSEE). Those 
regulations that will apply to the authority of BSEE organization will 
remain in 30 CFR chapter II, but be retitled ``Bureau of Safety and 
Environmental Enforcement.'' This rule removes from chapter II those 
regulations that will apply to the authority of BOEM and recodifies 
them into a new 30 CFR chapter V entitled ``Bureau of Ocean Energy 
Management.''

DATES: Effective Dates: This rule is effective on October 1, 2011.

FOR FURTHER INFORMATION CONTACT: Kumkum Ray, Regulations and Standards 
Branch, (703) 787-1604, e-mail address: kumkum.ray@boemre.gov.

SUPPLEMENTARY INFORMATION:

Background

Order of Events

    On May 19, 2010, the Secretary of the Department of the Interior 
(Secretary) issued Secretarial Order No. 3299, which announced the 
restructuring of the former Minerals Management Service (MMS). The 
restructuring divided the responsibilities of the former MMS into three 
new bureaus within the Department of the Interior:
    (1) Bureau of Ocean Energy Management (BOEM).
    (2) Bureau of Safety and Environmental Enforcement (BSEE).
    (3) Office of Natural Resources Revenue (ONRR).
    On June 18, 2010, the Secretary issued Secretarial Order No. 3302, 
which announced the name change of the former MMS to Bureau of Ocean 
Energy Management, Regulation and Enforcement (BOEMRE). This name, 
BOEMRE, will be in effect until the new organizations are in place 
October 1, 2011.
    On October 1, 2010, the functions of the former Minerals Revenue 
Management (MRM) officially transferred to ONRR, reporting to the 
Assistant Secretary for Policy, Management and Budget.
    On October 4, 2010, ONRR published a final rule in the Federal 
Register (75 FR 61051), moving the regulations related to its royalty 
and revenue functions from 30 CFR chapter II to chapter XII.
    October 1, 2011 will be the effective date of the separation of the 
[remaining components of] BOEMRE into BOEM and BSEE.

Responsibilities

    Secretarial Order No. 3299 established the responsibilities for 
BOEM, BSEE, and ONRR as follows:
    BOEM will be responsible for conventional (e.g., oil and gas) and 
renewable energy-related management functions including, but not 
limited to, activities involving resource evaluation, planning, and 
leasing, environmental science, and environmental analysis.
    BSEE will be responsible for safety and environmental enforcement 
functions including, but not limited to, the authority to permit 
activities, inspect, investigate, summon witnesses and produce 
evidence: levy penalties; cancel or suspend activities; and oversee 
safety, response and removal preparedness.
    ONRR is responsible for royalty and revenue management functions 
including, but not limited to, royalty and revenue collection, 
distribution, auditing and compliance, investigation and enforcement, 
and asset management for both onshore and offshore activities.
    Secretarial Order No. 3299 further established that BOEM and BSEE 
will be under the supervision of the Assistant Secretary for Land and 
Minerals Management (ASLM) and that ONRR will be under the supervision 
of the Assistant Secretary for Policy, Management and Budget. This 
order also directed the ASLM to ``take appropriate steps to ensure that 
this reorganization will provide that agency decisions are made in 
compliance with all applicable safety, environmental, and conservation 
laws and regulations * * *'' The reorganization of these regulations 
supports this directive.
    In a January 19, 2011, statement, the Secretary established the 
missions and functions of BOEM and BSEE as follows:
     BOEM Mission: Responsible for managing development of the 
nation's offshore resources in an environmentally and economically 
responsible way.
     BOEM Functions include: Leasing, Plan Administration, 
Environmental Studies, National Environmental Policy Act (NEPA) 
Analysis, Resource Evaluation, Economic Analysis, and the Renewable 
Energy Program.
     BSEE Mission: Enforce safety and environmental 
regulations.
     BSEE Functions include: All field operations including 
Permitting and Research, Inspections, Research, Offshore Regulatory 
Programs, Oil Spill Response, and newly formed Training and 
Environmental Compliance functions.

Rulemaking Procedure

    This rule pertains solely to the organization and codification of 
existing rules and related technical changes necessitated by a division 
of one agency into two separate agencies. It makes no changes to the 
substantive legal rights, obligations, or interests of affected 
parties. This rule therefore is a ``rule[] of agency organization, 
procedure or practice'' and is therefore exempt from the notice-and-
comment requirements of 5 U.S.C. 553 under 5 U.S.C. 553(b)(A). 
Additionally, for the same reasons, BOEMRE finds for good cause shown 
that notice and comment on this rule are unnecessary and contrary to 
the public interest under 5 U.S.C. 553(b)(B). Because this rule makes 
no changes to the legal obligations or rights of non-governmental 
entities, the Department further finds that good cause exists under 5 
U.S.C. 553(d)(3) to make this rule effective on October 1, 2011, rather 
than a full 30 days after publication in the Federal Register.

Proposed Rule

    BOEM and BSEE will also jointly issue a proposed rule that will 
address some more substantive changes to the regulations. In part, the 
proposed rule will address regulatory anomalies created by splitting 
the functions of one

[[Page 64433]]

agency into two bureaus. In certain cases, the split necessitated 
changing the wording of specific provisions. Rather than changing the 
wording in this final rule, we have concluded it is more appropriate to 
do so in a proposed rule. The proposed rule changes will be substantial 
enough in nature to necessitate public comments and publication of a 
Notice of Proposed Rulemaking (NPR).

Reorganization of CFR Title 30

Background Information

    This final rule assigns the regulations previously codified under 
Title 30 of the Code of Federal Regulations (30 CFR), chapter II--
Minerals Management Service, Department of the Interior, Subchapter A--
Minerals Revenue Management, Subchapter B--Offshore, and Subchapter C--
Appeals; to BSEE, under chapter II and to BOEM, under chapter V. The 
assignment of the regulations is based on the responsibilities and 
authorities established by Secretarial Order No. 3299, separating BSEE 
and BOEM and the January 19, 2011, statement that further clarified 
each bureau's mission and functions.
    To effectively manage the energy and mineral resources of the Outer 
Continental Shelf (OCS), the current regulations must be separated 
based on the responsibilities of the new bureaus. Based on the 
responsibilities established by Secretarial Order No. 3299, separating 
BOEMRE into BOEM and BSEE, this direct final rule reorganizes the 
regulations previously found in 30 CFR chapter II by:
    1. Retitling chapter II as ``Bureau of Safety and Environmental 
Enforcement'';
    2. Retaining the regulations that will be under the authority of 
BSEE in chapter II;
    3. Adding a new chapter, ``Chapter V--Bureau of Ocean Energy 
Management''; and
    4. Moving the regulations that will be under the authority of BOEM 
to 30 CFR chapter V.
    In addition to redesignating the regulations to the appropriate 
bureau, this rule makes minor supporting edits for clarification, 
consistency, or to reiterate current and longstanding practices. 
However, the regulatory requirements themselves are not changed. These 
edits generally fall under one of the following categories:
     Updates to cross-references to reflect the two new sets of 
rules, such as:
    [cir] Change Sec.  250.101(a) to 550.101(a)),
    [cir] Change Sec.  250.123 to 30 CFR 250.123,
    [cir] Change ``see Sec.  250.111'' to ``see Sec.  250.111 and 30 
CFR 550.111'';
     Change references from MMS or BOEMRE to BSEE or BOEM. It 
should be understood, however, that references to BSEE or BOEM actions 
before October 1, 2011, refer to the predecessor agency (MMS or BOEMRE) 
performing the functions specified in the regulations;
     Changes in the text to reference new chapter, section, or 
title headings;
     Correction of spelling or grammatical errors;
     Changes of physical and Web site addresses;
     Changes of titles, i.e., authorized manager (Regional 
Director, Regional Supervisor etc.), and specifying the appropriate 
title, based on the bureau (i.e., BSEE Regional Director or BOEM 
Regional Director); and/or

Cross-References

    This direct final rule is not intended to make any substantive 
changes to the regulations or requirements previously set forth in 30 
CFR chapter II. In redesignating the regulations, various provisions of 
this rule contain cross-references to earlier approvals or other 
actions taken under redesignated sections. This rule replaces the 
cross-references to previous sections with cross-references to new 
sections.

Forms and Information Collection

    BOEM and BSEE will rename forms as either BOEM or BSEE forms; MMS 
will be removed from the form names. Each form will retain its already 
assigned number, except that all numbers will now be four digits. We 
will add a zero(s) in front of an existing form number where necessary 
(e.g., form MMS-123 will now become form BSEE-0123). The forms 
themselves are not changed by this rule.
    There are no Information Collection (IC) burden changes in this 
rule.

Assignment of Regulations and Explanations

    All sections that BSEE retains keep their existing numbers, 
reflecting their existing location in 30 CFR chapter II. BOEM citations 
are renumbered using the number ``5'' as the first number for the part, 
reflecting their new location in 30 CFR chapter V.
    The following table (Table A) provides an overview of the 
assignment of regulations between BOEM and BSEE, by part. Many parts 
are retained in their entirety by BSEE or moved in their entirety to 
BOEM. Additional details of how other parts are divided between the two 
bureaus follow in Tables B through O.

                        Table A--Derivation Table
                       Title 30--Mineral Resources
      Chapter II--Bureau of Ocean Energy Management, Regulation and
                               Enforcement
------------------------------------------------------------------------
         Current part              New location        Justification
------------------------------------------------------------------------
                Subchapter A--Minerals Revenue Management
------------------------------------------------------------------------
Part 203--Relief or Reduction   Retained in its    BSEE will oversee the
 in Royalty Rates.               entirety in        administration of
                                 BSEE, chapter II.  royalty relief
                                                    awarded after lease
                                                    issuance as an
                                                    operational
                                                    responsibility.
                                                    However, BOEM will
                                                    set the terms and
                                                    conditions of any
                                                    future leases issued
                                                    with royalty relief
                                                    provisions.
Part 219--Distribution and      Moved in its       BOEM will perform
 Disbursement of Royalties,      entirety to        revenue share
 Rentals, and Bonuses.           BOEM, chapter V,   calculations for
                                 part 519.          Outer Continental
                                                    Shelf (OCS) receipts
                                                    shared under the
                                                    Gulf of Mexico
                                                    Energy Security Act
                                                    (GOMESA). ONRR will
                                                    continue to
                                                    distribute the
                                                    revenue shares to
                                                    Gulf producing
                                                    States and Coastal
                                                    Political
                                                    Subdivisions.
------------------------------------------------------------------------
                         Subchapter B--Offshore
------------------------------------------------------------------------
Part 250--Oil and Gas and       Responsibilities   Both bureaus have
 Sulphur Operations in the       divided between    responsibilities
 Outer Continental Shelf.        BOEM and BSEE.     that are related to
                                                    operations on OCS
                                                    leases. These
                                                    responsibilities
                                                    were divided between
                                                    the two bureaus as
                                                    detailed in Table B.

[[Page 64434]]

 
Part 251--Geological and        Responsibilities   BOEM will be
 Geophysical (G&G)               divided between    responsible for
 Explorations of the Outer       BOEM and BSEE.     issuing the permits
 Continental Shelf.                                 and notices and
                                                    overseeing the
                                                    activities under the
                                                    approved permit, as
                                                    these are prelease,
                                                    resource assessment-
                                                    related activities.
                                                    BSEE will be
                                                    responsible for
                                                    issuing permits for
                                                    test drilling
                                                    activities under
                                                    their
                                                    responsibilities for
                                                    operations. Further
                                                    details are provided
                                                    in Table C.
Part 252--Outer Continental     Both BOEM and      Part 252 regulates
 Shelf (OCS) Oil and Gas         BSEE will have     how and when the
 Information Program.            this part in its   date and information
                                 entirety.          is released by the
                                                    OCS Oil and Gas
                                                    Information Program.
                                                    Since both bureaus
                                                    will collect,
                                                    maintain, and use
                                                    data and information
                                                    collected under this
                                                    program, both are
                                                    responsible for
                                                    managing the data
                                                    and determining how
                                                    and when the data
                                                    and information are
                                                    released. Further
                                                    details are provided
                                                    in Table D.
Part 253--Oil Spill Financial   Moved to BOEM in   BOEM is responsible
 Responsibility for Offshore     its entirety,      for all activities
 Facilities.                     chapter V, part    related to financial
                                 553.               assurance. Oil spill
                                                    financial
                                                    responsibility
                                                    requirements are
                                                    mandated by the Oil
                                                    Pollution Act of
                                                    1990 (OPA) that
                                                    applies to oil
                                                    handling activities
                                                    at any offshore
                                                    facility (whether or
                                                    not involved in oil
                                                    production) seaward
                                                    of the coastline.
                                                    Further details are
                                                    provided in Table E.
Part 254--Oil-Spill Response    Retained in its    All oil-spill related
 Requirements for Facilities     entirety in BSEE.  activities, except
 Located Seaward of the Coast                       for financial
 Line.                                              responsibility, will
                                                    fall under BSEE,
                                                    under its
                                                    responsibility for
                                                    oil-spill response.
                                                    Further details are
                                                    provided in Table F.
Part 256--Leasing of Sulphur    Responsibilities   BOEM has primary
 or Oil and Gas in the Outer     divided between    responsibility for
 Continental Shelf.              BOEM and BSEE.     leasing and leasing-
                                                    related activities.
                                                    Some
                                                    responsibilities
                                                    related to
                                                    operations and
                                                    production will be
                                                    in both bureaus.
                                                    Suspension-related
                                                    requirements will go
                                                    to BSEE. Further
                                                    details are provided
                                                    in Table G.
Part 259--Mineral Leasing:      Moved to BOEM in   BOEM is responsible
 Definitions.                    its entirety,      for leasing
                                 chapter V, part    activities. Further
                                 559.               details are provided
                                                    in Table H.
Part 260--Outer Continental     Moved to BOEM in   BOEM is responsible
 Shelf Oil and Gas Leasing.      its entirety,      for leasing
                                 chapter V, part    activities. Further
                                 560.               details are provided
                                                    in Table I.
Part 270--Nondiscrimination in  Both BOEM and      Both BOEM and BSEE
 the Outer Continental Shelf.    BSEE will have     are responsible for
                                 this part in its   ensuring that
                                 entirety.          lessees and
                                                    operators comply
                                                    with section 604 of
                                                    the OCSLA of 1978,
                                                    which provides that
                                                    ``no person shall,
                                                    on the grounds of
                                                    race, creed, color,
                                                    national origin, or
                                                    sex, be excluded
                                                    from receiving or
                                                    participating in any
                                                    activity, sale, or
                                                    employment,
                                                    conducted pursuant
                                                    to the provisions of
                                                    . . . the Outer
                                                    Continental Shelf
                                                    Lands Act.'' Further
                                                    details are provided
                                                    in Table J.
Part 280--Prospecting for       Moved to BOEM in   This part regulates
 Minerals Other Than Oil, Gas,   its entirety,      prospecting
 and Sulphur on the Outer        chapter V, part    activities or
 Continental Shelf.              580.               scientific research
                                                    activities on the
                                                    OCS in Federal
                                                    waters related to
                                                    hard minerals on
                                                    unleased lands or on
                                                    lands under lease to
                                                    a third party. These
                                                    activities fall
                                                    under BOEM
                                                    responsibilities for
                                                    managing the
                                                    development of
                                                    offshore resources
                                                    and activities on
                                                    unleased land or on
                                                    lands leased to a
                                                    third party. Further
                                                    details are provided
                                                    in Table K.
Part 281--Leasing of Minerals   Moved to BOEM in   This part regulates
 Other Than Oil, Gas, and        its entirety,      leasing for minerals
 Sulphur in the Outer            chapter V, part    other than oil, gas,
 Continental Shelf.              581.               and sulphur in the
                                                    OCS. Leasing
                                                    activities are a
                                                    BOEM responsibility.
                                                    Further details are
                                                    provided in Table L.
Part 282--Operations in the     Responsibilities   Both BOEM and BSEE
 Outer Continental Shelf for     divided between    have
 Minerals Other Than Oil, Gas,   BOEM and BSEE.     responsibilities for
 and Sulphur.                                       operations conducted
                                                    under a mineral
                                                    lease for OCS
                                                    minerals other than
                                                    oil, gas, or
                                                    sulphur. These
                                                    responsibilities
                                                    were divided between
                                                    the two bureaus as
                                                    detailed in Table M.
Part 285--Renewable Energy and  Moved in its       At this time, the
 Alternate Uses of Existing      entirety to        renewable energy
 Facilities on the Outer         BOEM, chapter V,   program will be
 Continental Shelf.              part 585.          managed under BOEM.
                                                    At a later date, the
                                                    renewable energy
                                                    program will be
                                                    reorganized and a
                                                    determination will
                                                    be made regarding
                                                    what functions will
                                                    be administered by
                                                    which agency.
------------------------------------------------------------------------
                          Subchapter C--Appeals
------------------------------------------------------------------------
Part 290--Appeal Procedures...  Both BOEM and      Appeal procedures
                                 BSEE will have     apply to decisions
                                 this part in its   and orders issued by
                                 entirety.          both BOEM and BSEE.
                                                    Further details are
                                                    provided in Table O.
Part 291--Open and              Retained in its    This part deals with
 Nondiscriminatory Access to     entirety in BSEE.  access to pipelines.
 Oil and Gas Pipelines under                        All aspects of
 the Outer Continental Shelf                        pipelines, including
 Lands Act.                                         operations are under
                                                    the responsibility
                                                    of BSEE. Further
                                                    details are provided
                                                    in Table P.
------------------------------------------------------------------------


[[Page 64435]]

    The reorganization of the individual parts and subparts is as 
follows:

Subchapter A--Minerals Revenue Management

Part 203--Relief or Reduction in Royalty Rates--Retained in Its 
Entirety in BSEE, Chapter II

    BSEE is responsible for the regulatory oversight of need-based 
royalty relief awarded after lease issuance and the tracking of all 
royalty-free production.

Part 219--Distribution and Disbursement of Royalties, Rentals, and 
Bonuses--Moved in Its Entirety to BOEM, Chapter V, Part 519

    BOEM will perform revenue share calculations for OCS receipts 
shared under GOMESA.

Subchapter B--Offshore

Part 250--Oil and Gas and Sulphur Operations in the Outer Continental 
Shelf

    Part 250 established the requirements for offshore oil, natural 
gas, and sulphur operations. These operations include activities after 
the lease is established. Most of current Part 250 will stay under 
BSEE, with some sections going to BOEM. The details of this division 
are as follows.

                  Table B--Detailed Table for Part 250
------------------------------------------------------------------------
                                   Implementing
   Current citation and BSEE     bureau and BOEM
   citation (if applicable)        citation (if         Explanation
                                   applicable)
------------------------------------------------------------------------
                           Subpart A--General
 
This subpart establishes the basic regulations for oil, gas, and sulphur
 exploration, development, and production operations in the OCS. Many of
 the requirements in this subpart represent joint responsibilities;
 therefore, they belong in both bureaus. Other requirements are the sole
 responsibility of one bureau.
------------------------------------------------------------------------
Sec.   250.101 Authority and    Both BSEE and      Establishes authority
 applicability.                  BOEM, Sec.         for the entire part,
                                 550.101.           allowing both
                                                    bureaus to have some
                                                    authority for
                                                    operations in the
                                                    OCS and both bureaus
                                                    need to establish
                                                    their authority.
                                                    This section also
                                                    establishes the
                                                    basic requirements
                                                    for OCS oil, gas,
                                                    and sulphur
                                                    operations.
Sec.   250.102 What does this   Both BSEE and      This section
 part do?.                       BOEM, Sec.         describes the
                                 550.102.           purpose of these
                                                    regulations (parts
                                                    250 and 550) and
                                                    provides a reference
                                                    table addressing
                                                    where to find
                                                    information for
                                                    conducting OCS
                                                    operations; it is
                                                    applicable to the
                                                    regulations in both
                                                    bureaus.
Sec.   250.103 Where can I      Both BSEE and      This section
 find more information about     BOEM, Sec.         establishes the
 the requirements in this        550.103.           authority for the
 part?                                              bureaus to issue
                                                    additional guidance
                                                    to lessees and
                                                    operators, in the
                                                    form of Notices to
                                                    Lessees and
                                                    Operators (NTLs),
                                                    and establishes the
                                                    expectation of the
                                                    lessees and
                                                    operators to respond
                                                    to that guidance.
Sec.   250.104 How may I        Both BSEE and      This section explains
 appeal a decision made under    BOEM, Sec.         how a lessee or
 MMS regulations?                550.104.           operator may appeal
                                                    a decision made by
                                                    either BSEE or BOEM,
                                                    it is informational
                                                    and important to
                                                    include in both sets
                                                    of regulations.
Sec.   250.105 Definitions....  Both BSEE and      This section contains
                                 BOEM, Sec.         the definitions used
                                 550.105.           in parts 250 and
                                                    550, the same
                                                    definitions will
                                                    apply to both sets
                                                    of regulations.
Sec.   250.106 What standards   Retained by BSEE.  This section defines
 will the Director use to                           the standards for
 regulate lease operations?                         performance that
                                                    BSEE will use to
                                                    regulate lease
                                                    operations, these
                                                    operations fall
                                                    under the authority
                                                    of BSEE.
Sec.   250.107 What must I do   Retained by BSEE.  This section
 to protect health, safety,                         establishes the
 property, and the                                  expectations for
 environment?                                       operators to protect
                                                    health, safety, and
                                                    the environment,
                                                    these
                                                    responsibilities
                                                    fall under the
                                                    authority of BSEE.
Sec.   250.108 What             Retained by BSEE.  Addresses cranes and
 requirements must I follow                         other material-
 for cranes and other material-                     handling equipment,
 handling equipment?                                which is related to
                                                    an offshore
                                                    operation that is
                                                    under the authority
                                                    of BSEE.
Sec.   250.109 What documents   Retained by BSEE.  These sections
 must I prepare and maintain                        address welding
 related to welding?                                requirements, which
                                                    are related to
                                                    offshore operations
                                                    that are under the
                                                    authority of BSEE.
Sec.   250.110 What must I
 include in my welding plan?
Sec.   250.111 Who oversees
 operations under my welding
 plan?
Sec.   250.112 What standards
 must my welding equipment
 meet?
Sec.   250.113 What procedures
 must I follow when welding?
Sec.   250.114 How must I       Retained by BSEE.  Addresses the
 install and operate                                installation and
 electrical equipment?                              operation of
                                                    electrical
                                                    equipment, which are
                                                    related to offshore
                                                    operations that are
                                                    under the authority
                                                    of BSEE.
Sec.   250.115 How do I         Moved to BOEM,     Addresses well
 determine well producibility?   Sec.  Sec.         producibility that
                                 550.115,           is under the
                                 550.116, and       authority of BOEM.
                                 550.117.
Sec.   250.116 How do I
 determine producibility if my
 well is in the Gulf of
 Mexico?
Sec.   250.117 How does a
 determination of well
 producibility affect royalty
 status?
Sec.   250.118 Will MMS         Retained by BSEE.  Addresses gas
 approve gas injection?                             injection operations
                                                    that are under the
                                                    authority of BSEE.

[[Page 64436]]

 
Sec.   250.119 Will MMS         Moved to BOEM,     Addresses subsurface
 approve subsurface gas          Sec.   550.119.    gas storage that is
 storage?                                           under the authority
                                                    of BOEM.
Sec.   250.120 How does         Retained by BSE..  These pertain to gas
 injecting, storing, or                             storage operations
 treating gas affect my                             that are under the
 royalty payments?                                  authority of BSEE.
Sec.   250.121 What happens
 when the reservoir contains
 both original gas in place
 and injected gas?
Sec.   250.122 What effect      Both BSEE and      This section
 does subsurface storage have    BOEM Sec.          clarifies that an
 on the lease term?              550.122.           approved storage
                                                    project has no
                                                    effect on lease
                                                    term.
Sec.   250.123 Will MMS allow   Moved to BOEM,     This section allows
 gas storage on unleased         Sec.   550.123.    gas storage on
 lands?                                             unleased lands,
                                                    through a right-of-
                                                    use and easement
                                                    (RUE). RUEs are
                                                    issued by BOEM,
                                                    under their
                                                    responsibility for
                                                    resource management.
Sec.   250.124 Will MMS         Retained by BSEE.  This section
 approve gas injection into                         addresses gas
 the cap rock containing a                          injection
 sulphur deposit?                                   operations.
                                                   Offshore operations
                                                    are under the
                                                    authority of BSEE.
Sec.   250.125 Service fees...  Both BSEE and      Both BSEE and BOEM
                                 BOEM, Sec.         will oversee
                                 550.125.           activities that
                                                    require collection
                                                    of a service fee.
Sec.   250.126 Electronic       Both BSEE and      Provides information
 payment instructions.           BOEM, Sec.         on how to pay the
                                 550.126.           fees collected by
                                                    BSEE and BOEM.
Sec.   250.130 Why does MMS     Retained by BSEE.  BSEE will be
 conduct inspections?                               responsible for
                                                    issuing permits and
                                                    notices and
                                                    inspecting the
                                                    operations under
                                                    approved leases,
                                                    plans, and permit.
Sec.   250.131 Will MMS notify  Retained by BSEE.  BSEE will be
 me before conducting an                            responsible for
 inspection?                                        inspecting
                                                    operations and
                                                    activities on the
                                                    OCS.
Sec.   250.132 What must I do
 when MMS conducts an
 inspection?
Sec.   250.133 Will MMS
 reimburse me for my expenses
 related to inspections?
Sec.   250.135 What will MMS    Both BSEE and      BSEE is responsible
 do if my operating              BOEM, Sec.  Sec.   for finding operator
 performance is unacceptable?      550.135 and      performance
                                 550.136.           unacceptable under
                                                    the criteria of Sec.
                                                      550.136, but the
                                                    final adjudication
                                                    is a BOEM action.
Sec.   250.136 How will MMS
 determine if my operating
 performance is unacceptable?
Sec.   250.140 When will I      Both BSEE and      Both BSEE and BOEM
 receive an oral approval?       BOEM, Sec.         may grant verbal
                                 550.140, except    approvals for
                                 for paragraph      activities and
                                 (c), which will    operations under
                                 remain with BSEE   their respective
                                 only.              authorities.
                                                    Paragraph (c)
                                                    addresses oral
                                                    approvals for gas
                                                    flaring that will be
                                                    regulated only by
                                                    BSEE.
Sec.   250.141 May I ever use   Both BSEE and      This section explains
 alternate procedures or         BOEM, Sec.         how a lessee or
 equipment?                      550.141.           operator may request
                                                    to use alternate
                                                    procedures or
                                                    equipment that is
                                                    not addressed in
                                                    current regulations.
                                                    It is informational
                                                    and important to
                                                    include in both sets
                                                    of regulations.
Sec.   250.142 How do I         Both BSEE and      This section provides
 receive approval for            BOEM, Sec.         information on how a
 departures?                     550.142.           lessee or operator
                                                    can request a
                                                    departure from the
                                                    applicable BSEE or
                                                    BOEM regulations.
                                                    BSEE and BOEM may
                                                    grant departures for
                                                    activities and
                                                    operations under the
                                                    respective
                                                    authorities.
Sec.   250.143 How do I         Moved to BOEM,     This section
 designate an operator?          Sec.   550.143.    addresses the
                                                    designation of an
                                                    operator that is
                                                    under the authority
                                                    of BOEM.
Sec.   250.144 How do I         Moved to BOEM,     This section
 designate a new operator when   Sec.   550.144.    addresses the
 a designation of operator                          designation of an
 terminates?                                        operator that is
                                                    under the authority
                                                    of BOEM.
Sec.   250.145 How do I         Both BSEE and      This section
 designate an agent or a local   BOEM, Sec.         addresses the
 agent?                          550.145.           designation of an
                                                    agent that is under
                                                    the authority of
                                                    both BSEE and BOEM.
Sec.   250.146 Who is           Both BSEE and      This section provides
 responsible for fulfilling      BOEM, Sec.         information on who
 leasehold obligations?          550.146.           is responsible for
                                                    fulfilling leasehold
                                                    obligations. These
                                                    activities are
                                                    conducted under the
                                                    authority of both
                                                    BSEE and BOEM.
Sec.   250.150 How do I name    Retained by BSEE.  This section provides
 facilities and wells in the                        information on
 Gulf of Mexico Region?                             naming facilities
                                                    and wells in the
                                                    Gulf of Mexico
                                                    region that is under
                                                    the authority of
                                                    BSEE.
Sec.   250.151 How do I name    Retained by BSEE.  This section provides
 facilities in the Pacific                          information on
 Region?                                            naming facilities
                                                    and wells in the
                                                    Pacific region that
                                                    are under the
                                                    authority of BSEE.
Sec.   250.152 How do I name    Retained by BSEE.  This section provides
 facilities in the Alaska                           information on
 Region?                                            naming facilities
                                                    and wells in the
                                                    Alaska region that
                                                    are under the
                                                    authority of BSEE.
Sec.   250.153 Do I have to     Retained by BSEE.  This section provides
 rename an existing facility                        information on
 or well?                                           renaming existing
                                                    facilities and wells
                                                    that are under the
                                                    authority of BSEE.
Sec.   250.154 What             Retained by BSEE.  This section provides
 identification signs must I                        information on the
 display?                                           required
                                                    identification signs
                                                    that must be
                                                    displayed that are
                                                    under the authority
                                                    of BSEE.

[[Page 64437]]

 
Sec.   250.160 When will MMS    Moved to BOEM,     This section provides
 grant me a right-of-use and     Sec.   550.160.    information on the
 easement, and what                                 requirements that
 requirements must I meet?                          must be met to
                                                    obtain a RUE. RUEs
                                                    are issued by BOEM
                                                    under their
                                                    responsibility for
                                                    resource management.
Sec.   250.161 What else must   Moved to BOEM,     This section provides
 I submit with my application?   Sec.   550.161.    information on
                                                    additional
                                                    requirements that
                                                    must be contained in
                                                    the RUE application.
                                                    RUEs are issued by
                                                    BOEM under their
                                                    responsibility for
                                                    resource management.
Sec.   250.162 May I continue   Moved to BOEM,     This section provides
 my right-of-use and easement    Sec.   550.162.    information on RUEs
 after the termination of any                       that are issued by
 lease on which it is                               BOEM under their
 situated?                                          responsibility for
                                                    resource management.
Sec.   250.163 If I have a      Moved to BOEM,     This section concerns
 State lease, will MMS grant     Sec.   550.163.    RUEs that are issued
 me a right-of-use and                              by BOEM under their
 easement?                                          responsibility for
                                                    resource management.
Sec.   250.164 If I have a      Moved to BOEM,     This section provides
 State lease, what conditions    Sec.   550.164.    information on RUEs
 apply for a right-of-use and                       that are issued by
 easement?                                          BOEM under their
                                                    responsibility for
                                                    resource management.
Sec.   250.165 If I have a      Moved to BOEM,     This section provides
 State lease, what fees do I     Sec.   550.165.    information on RUEs
 have to pay for a right-of-                        that are issued by
 use and easement?                                  BOEM under their
                                                    responsibility for
                                                    resource management.
Sec.   250.166 If I have a      Moved to BOEM,     This section provides
 State lease, what surety bond   Sec.   550.166.    information on RUEs
 must I have for a right-of-                        that are issued by
 use and easement?                                  BOEM under their
                                                    responsibility for
                                                    resource management.
Sec.   250.168 May operations   Retained by BSEE.  These sections
 or production be suspended?                        address suspension
                                                    of operations or
                                                    production. Offshore
                                                    operations are under
                                                    the authority of
                                                    BSEE.
Sec.   250.169 What effect
 does suspension have on my
 lease?
Sec.   250.170 How long does a
 suspension last?
Sec.   250.171 How do I
 request a suspension?
Sec.   250.172 When may the     Retained by BSEE.  These sections
 Regional Supervisor grant or                       address suspension
 direct an SOO or SOP?                              of operations or
                                                    production. Offshore
                                                    operations are under
                                                    the authority of
                                                    BSEE.
Sec.   250.173 When may the     Retained by BSEE.
 Regional Supervisor direct an
 SOO or SOP?
Sec.   250.174 When may the     Retained by BSEE.
 Regional Supervisor grant or
 direct an SOP?
Sec.   250.175 When may the     Retained by BSEE.  This section
 Regional Supervisor grant an                       addresses suspension
 SOO?                                               of operations.
                                                    Offshore operations
                                                    are under the
                                                    authority of BSEE.
Sec.   250.176 Does a           Retained by BSEE.  These sections
 suspension affect my royalty                       address suspension
 payment?                                           of operations or
                                                    production. Offshore
                                                    operations are under
                                                    the authority of
                                                    BSEE.
Sec.   250.177 What additional
 requirements may the Regional
 Supervisor order for a
 suspension?
Sec.   250.180 What am I        Retained by BSEE.  This section
 required to do to keep my                          addresses
 lease term in effect?                              requirements for
                                                    keeping a lease term
                                                    in effect. BSEE will
                                                    determine if a lease
                                                    meets these
                                                    requirements.
Sec.   250.181 When may the     Moved to BOEM,     This section
 Secretary cancel my lease and   Sec.   550.181.    addresses lease
 when am I compensated for                          cancellations.
 cancellation?                                      Offshore lease
                                                    administration is
                                                    under the authority
                                                    of BOEM. Past the
                                                    primary lease term,
                                                    BSEE has greater
                                                    authority over lease
                                                    extensions via
                                                    operations or
                                                    suspensions; BOEM
                                                    continues its lease
                                                    administration
                                                    function.
Sec.   250.182 When may the     Moved to BOEM,     This section
 Secretary cancel a lease at     Sec.   550.182.    addresses lease
 the exploration stage?                             cancellations.
                                                    Offshore lease
                                                    administration,
                                                    including lease
                                                    terms, is under the
                                                    authority of BOEM.
                                                    Past the primary
                                                    lease term, BSEE has
                                                    greater authority
                                                    over lease
                                                    extensions via
                                                    operations or
                                                    suspensions; BOEM
                                                    continues its lease
                                                    administration
                                                    function.
Sec.   250.183 When may MMS or  Moved to BOEM,     This section
 the Secretary extend or         Sec.   550.183.    addresses lease
 cancel a lease at the                              cancellations.
 development and production                         Offshore lease
 stage?                                             administration, is
                                                    under the authority
                                                    of BOEM. Past the
                                                    primary lease term,
                                                    BSEE has greater
                                                    authority over lease
                                                    extensions via
                                                    operations or
                                                    suspensions; BOEM
                                                    continues its lease
                                                    administration
                                                    function.
Sec.   250.184 What is the      Moved to BOEM,     This section
 amount of compensation for      Sec.   550.184.    addresses lease
 lease cancellation?                                cancellations.
                                                    Offshore lease
                                                    administration,
                                                    including lease
                                                    terms, is under the
                                                    authority of BOEM.
Sec.   250.185 When is there    Moved to BOEM,     This section
 no compensation for a lease     Sec.   550.185.    addresses lease
 cancellation?                                      cancellations.
                                                    Offshore lease
                                                    administration,
                                                    including lease
                                                    terms, is under the
                                                    authority of BOEM.

[[Page 64438]]

 
Sec.   250.186 What reporting   Both BSEE and      This section provides
 information and report forms    BOEM, Sec.         information
 must I submit?                  550.186.           concerning reporting
                                                    requirements and
                                                    form submission This
                                                    information is
                                                    applicable to both
                                                    BSEE and BOEM
                                                    activities.
Sec.   250.187 What are MMS'    Retained by BSEE.  This section
 incident reporting                                 addresses incident
 requirements?                                      reporting
                                                    requirements for
                                                    offshore operations
                                                    that are under the
                                                    authority of BSEE.
Sec.   250.188 What incidents   Retained by BSEE.  This section
 must I report to MMS and when                      addresses incident
 must I report them?                                reporting
                                                    requirements for
                                                    offshore operations
                                                    that are under the
                                                    authority of BSEE.
Sec.   250.189 Reporting        Retained by BSEE.  This section
 requirements for incidents                         addresses incident
 requiring immediate                                reporting
 notification.                                      requirements for
                                                    offshore operations
                                                    that are under the
                                                    authority of BSEE.
Sec.   250.190 Reporting        Retained by BSEE.  This section
 requirements for incidents                         addresses incident
 requiring written                                  reporting
 notification.                                      requirements for
                                                    offshore operations
                                                    that are under the
                                                    authority of BSEE.
Sec.   250.191 How does MMS     Retained by BSEE.  This section
 conduct incident                                   addresses incident
 investigations?                                    investigations for
                                                    offshore operations
                                                    that are under the
                                                    authority of BSEE.
Sec.   250.192 What reports     Retained by BSEE.  This section requires
 and statistics must I submit                       operators to submit
 relating to a hurricane,                           information relating
 earthquake, or other natural                       to the impact of
 occurrence?                                        hurricanes on on-
                                                    going offshore
                                                    operations, which
                                                    are under the
                                                    authority of BSEE.
Sec.   250.193 Reports and      Retained by BSEE.  This section
 investigations of apparent                         addresses incident
 violations.                                        reporting
                                                    requirements for
                                                    offshore operations
                                                    that are under the
                                                    authority of BSEE.
Sec.   250.194 How must I       Moved to BOEM,     BOEM is responsible
 protect archaeological          paragraph (c)      for plans. Paragraph
 resources?                      retained by BSEE   (c) directs
                                 and also in BOEM   operators to report
                                 with cross         to BSEE any
                                 reference.         archaeological
                                                    resource discovered
                                                    while conducting
                                                    operations in a
                                                    lease or right-of-
                                                    way area.
Sec.   250.195 What             Retained by BSEE.  This section
 notification does MMS require                      addresses the
 on the production status of                        production status of
 wells?                                             wells. This
                                                    information is
                                                    required to
                                                    determine when a
                                                    well begins to
                                                    actively produce.
                                                    BSEE will oversee
                                                    this function under
                                                    their responsibility
                                                    for offshore
                                                    operations.
Sec.   250.196 Reimbursements   Both BSEE and      Data and information
 for reproduction and            BOEM, Sec.         may be requested by
 processing costs.               550.196.           either BSEE or BOEM.
Sec.   250.197 Data and         BOEM--Introductor  Both BSEE and BOEM
 information to be made          y paragraph and    will collect and be
 available to the public or      paragraphs         responsible for
 for limited inspection.         (a)(6), (9),       various types of
                                 (10), (b),         information. This
                                 (c)(4), (5), and   section describes
                                 (6).               when the information
                                                    collected will be
                                                    made available to
                                                    the public and what
                                                    data and information
                                                    will be made
                                                    available for
                                                    limited inspection.
                                                    The section was
                                                    divided based on the
                                                    type of data and
                                                    information
                                                    addressed in each
                                                    paragraph.
                                BSEE--Introductor
                                 y paragraph and
                                 paragraphs
                                 (a)(1) through
                                 (5), (7), (8),
                                 (b), (c)(1)
                                 through (5) and
                                 (7) retained in
                                 BSEE.
Sec.   250.198 Documents        Retained by BSEE.  This section
 incorporated by reference.                         addresses documents
                                                    incorporated by
                                                    reference and
                                                    pertains to both
                                                    BSEE and BOEM
                                                    activities--e.g.
                                                    Renewable Energy in
                                                    BOEM.
Sec.   250.199 Paperwork        Both BSEE and      This section
 Reduction Act statements--      BOEM, Sec.         addresses the
 information collection.         550.199.           Paperwork Reduction
                                                    Act that is
                                                    applicable to both
                                                    BSEE and BOEM.
------------------------------------------------------------------------
                    Subpart B--Plans and Information
 
The plans function, which includes approving Exploration Plans and
 Development and Production Plans, falls under the jurisdiction of BOEM,
 under its authority to manage development of the Nation's offshore
 resources in an environmentally and economically responsible way.
 Therefore, most of Subpart B is being moved to BOEM. BSEE is
 responsible for Deepwater Operations Plans (DWOPs).
------------------------------------------------------------------------
Sec.   250.200 Definitions....  Both BSEE and      Definitions section,
                                 BOEM, Sec.         the same definitions
                                 550.200.           apply to both
                                                    bureaus.
Sec.   250.201 What plans and   Both BSEE and      This section
 information must I submit       BOEM, Sec.         addresses plans that
 before I conduct any            550.201.           are the
 activities on my lease or                          responsibility of
 unit?                                              BOEM. BSEE is
                                                    responsible for
                                                    DWOPs.
Sec.   250.202 What criteria    Moved to BOEM,     This section
 must the Exploration Plan       Sec.   550.202.    addresses plans that
 (EP), Development and                              are the
 Production Plan (DPP), or                          responsibility of
 Development Operations                             BOEM.
 Coordination Document (DOCD)
 meet?
Sec.   250.203 Where can wells  Moved to BOEM,     This section
 be located under an EP, DPP,    Sec.   550.203.    addresses plans that
 or DOCD?                                           are the
                                                    responsibility of
                                                    BOEM.

[[Page 64439]]

 
Sec.   250.204 How must I       Retained by BSEE.  This section
 protect the rights of the                          describes the
 Federal Government?                                responsibilities of
                                                    the operator to
                                                    protect the rights
                                                    of the Federal
                                                    Government while
                                                    conducting
                                                    operations on their
                                                    lease or units. BSEE
                                                    will be responsible
                                                    for offshore
                                                    operations and
                                                    ensuring operators
                                                    fulfill these
                                                    obligations.
Sec.   250.205 Are there        Retained by BSEE.  This section
 special requirements if my                         describes the
 well affects an adjacent                           measures operators
 property?                                          must take to protect
                                                    the rights of
                                                    adjacent lessees
                                                    during offshore
                                                    operations. Offshore
                                                    operations are under
                                                    the authority of
                                                    BSEE.
Sec.   250.206 How do I submit  Moved to BOEM,     This section
 the EP, DPP, or DOCD?           Sec.   550.206.    addresses plans that
                                                    are the
                                                    responsibility of
                                                    BOEM.
Sec.   250.207 What ancillary   Moved to BOEM,     This section is under
 activities may I conduct?       Sec.   550.207.    the responsibility
                                                    of BOEM.
Sec.   250.208 If I conduct     Moved to BOEM,     This section is under
 ancillary activities, what      Sec.   550.208.    the responsibility
 notices must I provide?                            of BOEM.
Sec.   250.209 What is the MMS  Moved to BOEM,     This section is under
 review process for the          Sec.   550.209.    the responsibility
 notice?                                            of BOEM.
Sec.   250.210 If I conduct     Moved to BOEM,     This section is under
 ancillary activities, what      Sec.   550.210.    the responsibility
 reporting and data/                                of BOEM.
 information retention
 requirements must I satisfy?
Sec.   250.211 What must the    Moved to BOEM,     This section
 EP include?                     Sec.   550.211.    addresses plans that
                                                    are the
                                                    responsibility of
                                                    BOEM.
Sec.   250.212 What             Moved to BOEM,     This section
 information must accompany      Sec.   550.212.    addresses plans that
 the EP?                                            are the
                                                    responsibility of
                                                    BOEM.
Sec.   250.213 What general     Moved to BOEM,     This section
 information must accompany      Sec.   550.213.    addresses plans that
 the EP?                                            are the
                                                    responsibility of
                                                    BOEM.
Sec.   250.214 What geological  Moved to BOEM,     This section
 and geophysical (G&G)           Sec.   550.214.    addresses plans that
 information must accompany                         are the
 the EP?                                            responsibility of
                                                    BOEM.
Sec.   250.215 What hydrogen    Moved to BOEM,     This section
 sulfide (H2S) information       Sec.   550.215.    addresses plans that
 must accompany the EP?                             are the
                                                    responsibility of
                                                    BOEM.
Sec.   250.216 What             Moved to BOEM,     This section
 biological, physical, and       Sec.   550.216.    addresses plans that
 socioeconomic information                          are the
 must accompany the EP?                             responsibility of
                                                    BOEM.
Sec.   250.217 What solid and   Moved to BOEM,     This section
 liquid wastes and discharges    Sec.   550.217.    addresses plans that
 information and cooling water                      are the
 intake information must                            responsibility of
 accompany the EP?                                  BOEM.
Sec.   250.218 What air         Moved to BOEM,     This section
 emissions information must      Sec.   550.218.    addresses plans that
 accompany the EP?                                  are the
                                                    responsibility of
                                                    BOEM.
Sec.   250.219 What oil and     Moved to BOEM,     This section
 hazardous substance spills      Sec.   550.219.    addresses plans that
 information must accompany                         are the
 the EP?                                            responsibility of
                                                    BOEM.
Sec.   250.220 If I propose     Moved to BOEM,     This section
 activities in the Alaska OCS    Sec.   550.220.    addresses plans that
 Region, what planning                              are the
 information must accompany                         responsibility of
 the EP?                                            BOEM.
Sec.   250.221 What             Moved to BOEM,     This section
 environmental monitoring        Sec.   550.221.    addresses plans that
 information must accompany                         are the
 the EP?                                            responsibility of
                                                    BOEM.
Sec.   250.222 What lease       Moved to BOEM,     This section
 stipulations information must   Sec.   550.222.    addresses plans that
 accompany the EP?                                  are the
                                                    responsibility of
                                                    BOEM.
Sec.   250.223 What mitigation  Moved to BOEM,     This section
 measures information must       Sec.   550.223.    addresses plans that
 accompany the EP?                                  are the
                                                    responsibility of
                                                    BOEM.
Sec.   250.224 What             Moved to BOEM,     This section
 information on support          Sec.   550.224.    addresses plans that
 vessels, offshore vehicles,                        are the
 and aircraft you will use                          responsibility of
 must accompany the EP?                             BOEM.
Sec.   250.225 What             Moved to BOEM,     This section
 information on the onshore      Sec.   550.225.    addresses plans that
 support facilities you will                        are the
 use must accompany the EP?                         responsibility of
                                                    BOEM.
Sec.   250.226 What Coastal     Moved to BOEM,     This section
 Zone Management Act (CZMA)      Sec.   550.226.    addresses plans that
 information must accompany                         are the
 the EP?                                            responsibility of
                                                    BOEM.

[[Page 64440]]

 
Sec.   250.227 What             Moved to BOEM,     This section
 environmental impact analysis   Sec.   550.227.    addresses plans that
 (EIA) information must                             are the
 accompany the EP?                                  responsibility of
                                                    BOEM.
Sec.   250.228 What             Moved to BOEM,     This section
 administrative information      Sec.   550.228.    addresses plans that
 must accompany the EP?                             are the
                                                    responsibility of
                                                    BOEM.
Sec.   250.231 After receiving  Moved to BOEM,     This section
 the EP, what will MMS do?       Sec.   550.231.    addresses plans that
                                                    are the
                                                    responsibility of
                                                    BOEM.
Sec.   250.232 What actions     Moved to BOEM,     This section
 will MMS take after the EP is   Sec.   550.232.    addresses plans that
 deemed submitted?                                  are the
                                                    responsibility of
                                                    BOEM.
Sec.   250.233 What decisions   Moved to BOEM,     This section
 will MMS make on the EP and     Sec.   550.233.    addresses plans that
 within what timeframe?                             are the
                                                    responsibility of
                                                    BOEM.
Sec.   250.234 How do I submit  Moved to BOEM,     This section
 a modified EP or resubmit a     Sec.   550.234.    addresses plans that
 disapproved EP, and when will                      are the
 MMS make a decision?                               responsibility of
                                                    BOEM.
Sec.   250.235 If a State       Moved to BOEM,     This section
 objects to the EP's coastal     Sec.   550.235.    addresses plans that
 zone consistency                                   are the
 certification, what can I do?                      responsibility of
                                                    BOEM.
Sec.   250.241 What must the    Moved to BOEM,     This section
 DPP or DOCD include?            Sec.   550.241.    addresses plans that
                                                    are the
                                                    responsibility of
                                                    BOEM.
Sec.   250.242 What             Moved to BOEM,     This section
 information must accompany      Sec.   550.242.    addresses plans that
 the DPP or DOCD?                                   are the
                                                    responsibility of
                                                    BOEM.
Sec.   250.243 What general     Moved to BOEM,     This section
 information must accompany      Sec.   550.243.    addresses plans that
 the DPP or DOCD?                                   are the
                                                    responsibility of
                                                    BOEM.
Sec.   250.244 What geological  Moved to BOEM,     This section
 and geophysical (G&G)           Sec.   550.244.    addresses plans that
 information must accompany                         are the
 the DPP or DOCD?                                   responsibility of
                                                    BOEM.
Sec.   250.245 What hydrogen    Moved to BOEM,     This section
 sulfide (H2S) information       Sec.   550.245.    addresses plans that
 must accompany the DPP or                          are the
 DOCD?                                              responsibility of
                                                    BOEM.
Sec.   250.246 What mineral     Moved to BOEM,     This section
 resource conservation           Sec.   550.246.    addresses plans that
 information must accompany                         are the
 the DPP or DOCD?                                   responsibility of
                                                    BOEM.
Sec.   250.247 What             Moved to BOEM,     This section
 biological, physical, and       Sec.   550.247.    addresses plans that
 socioeconomic information                          are the
 must accompany the DPP or                          responsibility of
 DOCD?                                              BOEM.
Sec.   250.248 What solid and   Moved to BOEM,     This section
 liquid wastes and discharges    Sec.   550.248.    addresses plans that
 information and cooling water                      are the
 intake information must                            responsibility of
 accompany the DPP or DOCD?                         BOEM.
Sec.   250.249 What air         Moved to BOEM,     This section
 emissions information must      Sec.   550.249.    addresses plans that
 accompany the DPP or DOCD?                         are the
                                                    responsibility of
                                                    BOEM.
Sec.   250.250 What oil and     Moved to BOEM,     This section
 hazardous substance spills      Sec.   550.250.    addresses plans that
 information must accompany                         are the
 the DPP or DOCD?                                   responsibility of
                                                    BOEM.
Sec.   250.251 If I propose     Moved to BOEM,     This section
 activities in the Alaska OCS    Sec.   550.251.    addresses plans that
 Region, what planning                              are the
 information must accompany                         responsibility of
 the DPP?                                           BOEM.
Sec.   250.252 What             Moved to BOEM,     This section
 environmental monitoring        Sec.   550.252.    addresses plans that
 information must accompany                         are the
 the DPP or DOCD?                                   responsibility of
                                                    BOEM.
Sec.   250.253 What lease       Moved to BOEM,     This section
 stipulations information must   Sec.   550.253.    addresses plans that
 accompany the DPP or DOCD?                         are the
                                                    responsibility of
                                                    BOEM.
Sec.   250.254 What mitigation  Moved to BOEM,     This section
 measures information must       Sec.   550.254.    addresses plans that
 accompany the DPP or DOCD?                         are the
                                                    responsibility of
                                                    BOEM.
Sec.   250.255 What             Moved to BOEM,     This section
 decommissioning information     Sec.   550.255.    addresses plans that
 must accompany the DPP or                          are the
 DOCD?                                              responsibility of
                                                    BOEM.

[[Page 64441]]

 
Sec.   250.256 What related     Moved to BOEM,     This section
 facilities and operations       Sec.   550.256.    addresses plans that
 information must accompany                         are the
 the DPP or DOCD?                                   responsibility of
                                                    BOEM.
Sec.   250.257 What             Moved to BOEM,     This section
 information on the support      Sec.   550.257.    addresses plans that
 vessels, offshore vehicles,                        are the
 and aircraft you will use                          responsibility of
 must accompany the DPP or                          BOEM.
 DOCD?
Sec.   250.258 What             Moved to BOEM,     This section
 information on the onshore      Sec.   550.258.    addresses plans that
 support facilities you will                        are the
 use must accompany the DPP or                      responsibility of
 DOCD?                                              BOEM.
Sec.   250.259 What sulphur     Moved to BOEM,     This section
 operations information must     Sec.   550.259.    addresses plans that
 accompany the DPP or DOCD?                         are the
                                                    responsibility of
                                                    BOEM.
Sec.   250.260 What Coastal     Moved to BOEM,     This section
 Zone Management Act (CZMA)      Sec.   550.260.    addresses plans that
 information must accompany                         are the
 the DPP or DOCD?                                   responsibility of
                                                    BOEM.
Sec.   250.261 What             Moved to BOEM,     This section
 environmental impact analysis   Sec.   550.261.    addresses plans that
 (EIA) information must                             are the
 accompany the DPP or DOCD?                         responsibility of
                                                    BOEM.
Sec.   250.262 What             Moved to BOEM,     This section
 administrative information      Sec.   550.262.    addresses plans that
 must accompany the DPP or                          are the
 DOCD?                                              responsibility of
                                                    BOEM.
Sec.   250.266 After receiving  Moved to BOEM,     This section
 the DPP or DOCD, what will      Sec.   550.266.    addresses plans that
 MMS do?                                            are the
                                                    responsibility of
                                                    BOEM.
Sec.   250.267 What actions     Moved to BOEM,     This section
 will MMS take after the DPP     Sec.   550.267.    addresses plans that
 or DOCD is deemed submitted?                       are the
                                                    responsibility of
                                                    BOEM.
Sec.   250.268 How does MMS     Moved to BOEM,     This section
 respond to recommendations?     Sec.   550.268.    addresses plans that
                                                    are the
                                                    responsibility of
                                                    BOEM.
Sec.   250.269 How will MMS     Moved to BOEM,     This section
 evaluate the environmental      Sec.   550.269.    addresses plans that
 impacts of the DPP or DOCD?                        are the
                                                    responsibility of
                                                    BOEM.
Sec.   250.270 What decisions   Moved to BOEM,     This section
 will MMS make on the DPP or     Sec.   550.270.    addresses plans that
 DOCD and within what                               are the
 timeframe?                                         responsibility of
                                                    BOEM.
Sec.   250.271 For what         Moved to BOEM,     This section
 reasons will MMS disapprove     Sec.   550.271.    addresses plans that
 the DPP or DOCD?                                   are the
                                                    responsibility of
                                                    BOEM.
Sec.   250.272 If a State       Moved to BOEM,     This section
 objects to the DPP's or         Sec.   550.272.    addresses plans that
 DOCD's coastal zone                                are the
 consistency certification,                         responsibility of
 what can I do?                                     BOEM.
Sec.   250.273 How do I submit  Moved to BOEM,     This section
 a modified DPP or DOCD or       Sec.   550.273.    addresses plans that
 resubmit a disapproved DPP or                      are the
 DOCD?                                              responsibility of
                                                    BOEM.
Sec.   250.280 How must I       Moved to BOEM,     This section
 conduct activities under the    Sec.   550.280.    addresses plans that
 approved EP, DPP, or DOCD?                         are the
                                                    responsibility of
                                                    BOEM.
Sec.   250.281 What must I do   Moved to BOEM,     This section
 to conduct activities under     Sec.   550.281.    addresses plans that
 the approved EP, DPP, or                           are the
 DOCD?                                              responsibility of
                                                    BOEM.
Sec.   250.282 Do I have to     Both BSEE and      Both BOEM and BSEE
 conduct post-approval           BOEM, Sec.         will have oversight
 monitoring?                     550.282.           functions for post-
                                                    approval monitoring.
Sec.   250.283 When must I      Moved to BOEM,     This section
 revise or supplement the        Sec.   550.283.    addresses plans that
 approved EP, DPP, or DOCD?                         are the
                                                    responsibility of
                                                    BOEM.
Sec.   250.284 How will MMS     Moved to BOEM,     This section
 require revisions to the        Sec.   550.284.    addresses plans that
 approved EP, DPP, or DOCD?                         are the
                                                    responsibility of
                                                    BOEM.
Sec.   250.285 How do I submit  Moved to BOEM,     This section
 revised and supplemental EPs,   Sec.   550.285.    addresses plans that
 DPPs, and DOCDs?                                   are the
                                                    responsibility of
                                                    BOEM.
Sec.   250.286 What is a DWOP?  Retained by BSEE.  This section
                                                    addresses DWOPs that
                                                    are part of Field
                                                    Operations and under
                                                    the authority of
                                                    BSEE.

[[Page 64442]]

 
Sec.   250.287 For what         Retained by BSEE.  This section
 development projects must I                        addresses DWOPs that
 submit a DWOP?                                     are part of Field
                                                    Operations and under
                                                    the authority of
                                                    BSEE.
Sec.   250.288 When and how     Retained by BSEE.  This section
 must I submit the Conceptual                       addresses DWOPs that
 Plan?                                              are part of Field
                                                    Operations and under
                                                    the authority of
                                                    BSEE.
Sec.   250.289 What must the    Retained by BSEE.  This section
 Conceptual Plan contain?                           addresses DWOPs that
                                                    are part of Field
                                                    Operations and under
                                                    the authority of
                                                    BSEE.
Sec.   250.290 What operations  Retained by BSEE.  This section
 require approval of the                            addresses DWOPs that
 Conceptual Plan?                                   are part of Field
                                                    Operations and under
                                                    the authority of
                                                    BSEE.
Sec.   250.291 When and how     Retained by BSEE.  This section
 must I submit the DWOP?                            addresses DWOPs that
                                                    are part of Field
                                                    Operations and under
                                                    the authority of
                                                    BSEE.
Sec.   250.292 What must the    Retained by BSEE.  This section
 DWOP contain?                                      addresses DWOPs that
                                                    are part of Field
                                                    Operations and under
                                                    the authority of
                                                    BSEE.
Sec.   250.293 What operations  Retained by BSEE.  This section
 require approval of the DWOP?                      addresses DWOPs that
                                                    are part of Field
                                                    Operations and under
                                                    the authority of
                                                    BSEE.
Sec.   250.294 May I combine    Retained by BSEE.  This section
 the Conceptual Plan and the                        addresses DWOPs that
 DWOP?                                              are part of Field
                                                    Operations and under
                                                    the authority of
                                                    BSEE.
Sec.   250.295 When must I      Retained by BSEE.  This section
 revise my DWOP?                                    addresses DWOPs that
                                                    are part of Field
                                                    Operations and under
                                                    the authority of
                                                    BSEE.
Sec.   250.296 When and how     Moved to BOEM,     This section
 must I submit a CID or a        Sec.   550.296.    addresses
 revision to a CID?                                 Conservation
                                                    Information
                                                    Documents (CIDs)
                                                    that are under the
                                                    authority of BOEM to
                                                    manage development
                                                    of the Nation's
                                                    offshore resources
                                                    in an
                                                    environmentally and
                                                    economically
                                                    responsible way.
Sec.   250.297 What             Moved to BOEM,     This section
 information must a CID          Sec.   550.297.    addresses CIDs that
 contain?                                           are under the
                                                    authority of BOEM to
                                                    manage development
                                                    of the Nation's
                                                    offshore resources
                                                    in an
                                                    environmentally and
                                                    economically
                                                    responsible way.
Sec.   250.298 How long will    Moved to BOEM,     This section
 MMS take to evaluate and make   Sec.   550.298.    addresses CIDs that
 a decision on the CID?                             are under the
                                                    authority of BOEM to
                                                    manage development
                                                    of the Nation's
                                                    offshore resources
                                                    in an
                                                    environmentally and
                                                    economically
                                                    responsible way.
Sec.   250.299 What operations  Moved to BOEM,     This section
 require approval of the CID?    Sec.   550.299.    addresses CIDs that
                                                    are under the
                                                    authority of BOEM to
                                                    manage development
                                                    of the Nation's
                                                    offshore resources
                                                    in an
                                                    environmentally and
                                                    economically
                                                    responsible way.
------------------------------------------------------------------------
               Subpart C--Pollution Prevention and Control
------------------------------------------------------------------------
 
Sec.   250.300 Pollution        Retained by BSEE.  This section
 prevention.                                        addresses pollution
                                                    prevention during
                                                    offshore operations.
                                                    Offshore operations
                                                    are under the
                                                    authority of BSEE.
Sec.   250.301 Inspection of    Retained by BSEE.  BSEE will be
 facilities.                                        responsible for all
                                                    inspection
                                                    activities on the
                                                    OCS.
Sec.   250.302 Definitions      Moved to BOEM,     This section pertains
 concerning air quality.         Sec.   550.302.    to air quality
                                                    concerns that are
                                                    under the authority
                                                    of BOEM.
Sec.   250.303 Facilities       Moved to BOEM,     This section pertains
 described in a new or revised   Sec.   550.303.    to air quality
 Exploration Plan or                                concerns that are
 Development and Production                         under the authority
 Plan.                                              of BOEM.
Sec.   250.304 Existing         Moved to BOEM,     This section pertains
 facilities.                     Sec.   550.304.    to air quality
                                                    concerns that are
                                                    under the authority
                                                    of BOEM.
------------------------------------------------------------------------
               Subpart D--Oil and Gas Drilling Operations
------------------------------------------------------------------------
 
Retained in its entirety by BSEE. This section addresses oil and gas
 drilling operations on the OCS. Offshore operations are under the
 authority of BSEE.
------------------------------------------------------------------------
            Subpart E--Oil and Gas Well-Completion Operations
 
Retained in its entirety by BSEE. BSEE will oversee all well-operations,
 under Field Operations, under its authority for ensuring safety and
 environmental compliance on the OCS.
------------------------------------------------------------------------
             Subpart F--Oil and Gas Well-Workover Operations
 
Retained in its entirety by BSEE. This subpart addresses Oil and Gas
 Well Workover Operations on the OCS. Offshore operations are the
 responsibility of BSEE, under its authority for ensuring safety and
 environmental compliance on the OCS.
------------------------------------------------------------------------
                          Subpart G--[Reserved]
------------------------------------------------------------------------
            Subpart H--Oil and Gas Production Safety Systems
 
Retained in its entirety by BSEE. Addresses oil and gas production
 safety systems used during offshore operations, which are under the
 authority of BSEE.
------------------------------------------------------------------------
                   Subpart I--Platforms and Structures
 
Retained in its entirety by BSEE. This section addresses platforms and
 structures on the OCS for offshore operations. Offshore operations are
 under the authority of BSEE.
------------------------------------------------------------------------

[[Page 64443]]

 
             Subpart J--Pipelines and Pipeline Rights-of-Way
 
Mostly retained by BSEE, except for provisions related to bond
 requirements (Sec.   250.1011). Bonding for all activities is the
 responsibility of BOEM, and the bonding section will be moved to Sec.
 550.1011. The rest of pipeline operations, including the issuance of
 pipeline rights-of-way, are under the authority of BSEE.
------------------------------------------------------------------------
Sec.   250.1000 General         Retained by BSEE.  This section
 requirements..                                     addresses pipelines
                                                    and pipeline rights-
                                                    of-way on the OCS,
                                                    which are offshore
                                                    operations. Offshore
                                                    operations are under
                                                    the authority of
                                                    BSEE.
Sec.   250.1001 Definitions...  Retained by BSEE.  This section
                                                    addresses pipelines
                                                    and pipeline rights-
                                                    of-way on the OCS,
                                                    which are offshore
                                                    operations. Offshore
                                                    operations are under
                                                    the authority of
                                                    BSEE.
Sec.   250.1002 Design          Retained by BSEE.  This section
 requirements for DOI                               addresses pipelines
 pipelines.                                         and pipeline rights-
                                                    of-way on the OCS,
                                                    which are offshore
                                                    operations. Offshore
                                                    operations are under
                                                    the authority of
                                                    BSEE.
Sec.   250.1003 Installation,   Retained by BSEE.  This section
 testing, and repair                                addresses pipelines
 requirements for DOI                               and pipeline rights-
 pipelines.                                         of-way on the OCS,
                                                    which are offshore
                                                    operations. Offshore
                                                    operations are under
                                                    the authority of
                                                    BSEE.
Sec.   250.1004 Safety          Retained by BSEE.  This section
 equipment requirements for                         addresses pipelines
 DOI pipelines.                                     and pipeline rights-
                                                    of-way on the OCS,
                                                    which are offshore
                                                    operations. Offshore
                                                    operations are under
                                                    the authority of
                                                    BSEE.
Sec.   250.1005 Inspection      Retained by BSEE.  This section
 requirements for DOI                               addresses pipelines
 pipelines.                                         and pipeline rights-
                                                    of-way on the OCS,
                                                    which are offshore
                                                    operations. Offshore
                                                    operations are under
                                                    the authority of
                                                    BSEE.
Sec.   250.1006 How must I      Retained by BSEE.  This section
 decommission and take out of                       addresses pipelines
 service a DOI pipeline?                            and pipeline rights-
                                                    of-way on the OCS,
                                                    which are offshore
                                                    operations. Offshore
                                                    operations are under
                                                    the authority of
                                                    BSEE.
Sec.   250.1007 What to         Retained by BSEE.  This section
 include in applications.                           addresses pipelines
                                                    and pipeline rights-
                                                    of-way on the OCS,
                                                    which are offshore
                                                    operations. Offshore
                                                    operations are under
                                                    the authority of
                                                    BSEE.
Sec.   250.1008 Reports.......  Retained by BSEE.  This section
                                                    addresses pipelines
                                                    and pipeline rights-
                                                    of-way on the OCS,
                                                    which are offshore
                                                    operations. Offshore
                                                    operations are under
                                                    the authority of
                                                    BSEE.
Sec.   250.1009 Requirements    Retained by BSEE.  This section
 to obtain pipeline right-of-                       addresses pipelines
 way grants.                                        and pipeline rights-
                                                    of-way on the OCS,
                                                    which are offshore
                                                    operations. The
                                                    pipeline rights-of-
                                                    way are so closely
                                                    related to the
                                                    regulation of
                                                    pipeline operations
                                                    that it is most
                                                    efficient to vest
                                                    the authority in
                                                    BSEE.
Sec.   250.1010 General         Retained by BSEE.  The pipeline rights-
 requirements for pipeline                          of-way are so
 right-of-way holders.                              closely related to
                                                    the regulation of
                                                    pipeline operations
                                                    that it is most
                                                    efficient to vest
                                                    the authority in
                                                    BSEE.
Sec.   250.1011 Bond            Moved to BOEM,     All bonding is under
 requirements for pipeline       Sec.   550.1011.   the authority of
 right-of-way holders.                              BOEM.
Sec.   250.1012 Required        Retained by BSEE.  The pipeline rights-
 payments for pipeline right-                       of-way are so
 of-way holders.                                    closely related to
                                                    the regulation of
                                                    pipeline operations
                                                    that it is most
                                                    efficient to vest
                                                    the authority in
                                                    BSEE.
Sec.   250.1013 Grounds for     Retained by BSEE.  The pipeline rights-
 forfeiture of pipeline right-                      of-way are so
 of-way grants.                                     closely related to
                                                    the regulation of
                                                    pipeline operations
                                                    that it is most
                                                    efficient to vest
                                                    the authority in
                                                    BSEE.
Sec.   250.1014 When pipeline   Retained by BSEE.  The pipeline rights-
 right-of-way grants expire.                        of-way are so
                                                    closely related to
                                                    the regulation of
                                                    pipeline operations
                                                    that it is most
                                                    efficient to vest
                                                    the authority in
                                                    BSEE.
Sec.   250.1015 Applications    Retained by BSEE.  The pipeline rights-
 for pipeline right-of-way                          of-way are so
 grants.                                            closely related to
                                                    the regulation of
                                                    pipeline operations
                                                    that it is most
                                                    efficient to vest
                                                    the authority in
                                                    BSEE.
Sec.   250.1016 Granting        Retained by BSEE.  The pipeline rights-
 pipeline rights-of-way.                            of-way are so
                                                    closely related to
                                                    the regulation of
                                                    pipeline operations
                                                    that it is most
                                                    efficient to vest
                                                    the authority in
                                                    BSEE.
Sec.   250.1017 Requirements    Retained by BSEE.  The pipeline rights-
 for construction under                             of-way are so
 pipeline right-of-way grants.                      closely related to
                                                    the regulation of
                                                    pipeline operations
                                                    that it is most
                                                    efficient to vest
                                                    the authority in
                                                    BSEE.
Sec.   250.1018 Assignment of   Retained by BSEE.  The pipeline rights-
 pipeline right-of-way grants.                      of-way are so
                                                    closely related to
                                                    the regulation of
                                                    pipeline operations
                                                    that it is most
                                                    efficient to vest
                                                    the authority in
                                                    BSEE.
Sec.   250.1019 Relinquishment  Retained by BSEE.  The pipeline rights-
 of pipeline right-of-way                           of-way are so
 grants.                                            closely related to
                                                    the regulation of
                                                    pipeline operations
                                                    that it is most
                                                    efficient to vest
                                                    the authority in
                                                    BSEE.
------------------------------------------------------------------------
             Subpart K--Oil and Gas Production Requirements
 
Mostly retained by BSEE, except for provisions related to static
 bottomhole pressure surveys and classifying reservoirs; BOEM will
 oversee these requirements because they are operator reporting
 requirements that can be separated from BSEE's enforcement
 responsibilities.
------------------------------------------------------------------------

[[Page 64444]]

 
Sec.   250.1150 What are the    Retained by BSEE.  This section
 general reservoir production                       addresses oil and
 requirements?                                      gas production
                                                    requirements that
                                                    are part of offshore
                                                    operations and are
                                                    under the authority
                                                    of BSEE.
Sec.   250.1151 How often must  Retained by BSEE.  This section
 I conduct well production                          addresses oil and
 tests?                                             gas production
                                                    requirements that
                                                    are part of offshore
                                                    operations and are
                                                    under the authority
                                                    of BSEE.
Sec.   250.1152 How do I        Retained by BSEE.  This section
 conduct well tests?                                addresses oil and
                                                    gas production
                                                    requirements that
                                                    are part of offshore
                                                    operations and are
                                                    under the authority
                                                    of BSEE.
Sec.   250.1153 When must I     Moved to BOEM,     BOEM will oversee
 conduct a static bottomhole     Sec.   550.1153.   these requirements
 pressure survey?                                   because they are
                                                    operator reporting
                                                    requirements that
                                                    can be separated
                                                    from BSEE's
                                                    enforcement
                                                    responsibilities.
Sec.   250.1154 How do I        Moved to BOEM,     BOEM will oversee
 determine if my reservoir is    Sec.   550.1154.   these requirements
 sensitive?                                         because they are
                                                    operator reporting
                                                    requirements that
                                                    can be separated
                                                    from BSEE's
                                                    enforcement
                                                    responsibilities.
Sec.   250.1155 What            Moved to BOEM,     BOEM will oversee
 information must I submit for   Sec.   550.1155.   these requirements
 sensitive reservoirs?                              because they are
                                                    operator reporting
                                                    requirements that
                                                    can be separated
                                                    from BSEE's
                                                    enforcement
                                                    responsibilities.
Sec.   250.1156 What steps      Retained by BSEE.  This section
 must I take to receive                             addresses oil and
 approval to produce within                         gas production
 500 feet of a unit or lease                        requirements that
 line?                                              are part of offshore
                                                    operations and are
                                                    under the authority
                                                    of BSEE.
Sec.   250.1157 How do I        Retained by BSEE.  This section
 receive approval to produce                        addresses oil and
 gas-cap gas from an oil                            gas production
 reservoir with an associated                       requirements that
 gas cap?                                           are part of offshore
                                                    operations and are
                                                    under the authority
                                                    of BSEE.
Sec.   250.1158 How do I        Retained by BSEE.  This section
 receive approval to downhole                       addresses oil and
 commingle hydrocarbons?                            gas production
                                                    requirements that
                                                    are part of offshore
                                                    operations and are
                                                    under the authority
                                                    of BSEE.
Sec.   250.1159 May the         Retained by BSEE.  This section
 Regional Supervisor limit my                       addresses oil and
 well or reservoir production                       gas production
 rates?                                             requirements that
                                                    are part of offshore
                                                    operations and are
                                                    under the authority
                                                    of BSEE.
Sec.   250.1160 When may I      Retained by BSEE.  This section
 flare or vent gas?                                 addresses oil and
                                                    gas production
                                                    requirements that
                                                    are part of offshore
                                                    operations and are
                                                    under the authority
                                                    of BSEE.
Sec.   250.1161 When may I      Retained by BSEE.  This section
 flare or vent gas for                              addresses oil and
 extended periods of time?                          gas production
                                                    requirements that
                                                    are part of offshore
                                                    operations and are
                                                    under the authority
                                                    of BSEE.
Sec.   250.1162 When may I      Retained by BSEE.  This section
 burn produced liquid                               addresses oil and
 hydrocarbons?                                      gas production
                                                    requirements that
                                                    are part of offshore
                                                    operations and are
                                                    under the authority
                                                    of BSEE.
Sec.   250.1163 How must I      Retained by BSEE.  This section
 measure gas flaring or                             addresses oil and
 venting volumes and liquid                         gas production
 hydrocarbon burning volumes,                       requirements that
 and what records must I                            are part of offshore
 maintain?                                          operations and are
                                                    under the authority
                                                    of BSEE.
Sec.   250.1164 What are the    Retained by BSEE.  This section
 requirements for flaring or                        addresses oil and
 venting gas containing H2S?                        gas production
                                                    requirements that
                                                    are part of offshore
                                                    operations and are
                                                    under the authority
                                                    of BSEE.
Sec.   250.1165 What must I do  Responsibilities   This section
 for enhanced recovery           divided between    addresses oil and
 operations?                     BSEE and BOEM,     gas production
                                 Sec.               requirements that
                                 550.1165(b).       are part of offshore
                                                    operations and are
                                                    under the authority
                                                    of BSEE. Paragraph
                                                    550.1165 (b) refers
                                                    operators to BSEE
                                                    for approval.
Sec.   250.1166 What            Responsibilities   BSEE will oversee
 additional reporting is         divided between    these requirements
 required for developments in    BSEE and BOEM,     because they are
 the Alaska OCS Region?          Sec.               operator reporting
                                 550.1166(c).       requirements.
                                                    Paragraph
                                                    550.1166(c) requires
                                                    the lessee/operator
                                                    to request the
                                                    Maximum Efficient
                                                    Rate (MER) when
                                                    submitting Form BOEM-
                                                    0127 as required
                                                    under Sec.
                                                    550.1155 for
                                                    sensitive
                                                    reservoirs.
Sec.   250.1167 What            Responsibilities   This section
 information must I submit       divided between    addresses
 with forms and for approvals?   BSEE and BOEM.     information to be
                                                    submitted; both BSEE
                                                    and BOEM functions.
------------------------------------------------------------------------
 Subpart L--Oil and Gas Production Measurement, Surface Commingling, and
                                Security
 
Retained in its entirety by BSEE. This subpart addresses production
 measurement, which is a responsibility of BSEE, under its authority for
 regulatory enforcement of conservation compliance.
------------------------------------------------------------------------
                         Subpart M--Unitization
 
Retained in its entirety by BSEE. This subpart addresses unitization,
 which is a responsibility of BSEE, under its authority for regulatory
 enforcement of conservation compliance.
------------------------------------------------------------------------

[[Page 64445]]

 
        Subpart N--Outer Continental Shelf (OCS) Civil Penalties
 
Retained in both bureaus in its entirety, with the exception of
 provisions in current Sec.   250.1460 that are specific to operational
 violations penalized only by BSEE. BOEM issues civil penalties for
 violations that occur prior to commencement of lease operations and not
 involving safety and environmental matters, but arising from the lease
 management functions and regulations of BOEM. BSEE issues civil
 penalties for violations that occur after permits are approved; these
 violations would include violations of lease terms or approved plans
 that occur during operations.
------------------------------------------------------------------------
         Subpart O--Well Control and Production Safety Training
 
Retained in its entirety by BSEE. This subpart establishes training
 requirements for individuals working in the offshore oil and gas
 industry; which is the responsibility of BSEE, under its authority for
 regulatory enforcement of safety related to offshore operations.
------------------------------------------------------------------------
                      Subpart P--Sulphur Operations
 
Retained in its entirety by BSEE. Sulphur operations are the
 responsibility of BSEE, under the authority for regulatory enforcement
 of safety, environment and conservation compliance of the Nation's
 offshore resources.
------------------------------------------------------------------------
                  Subpart Q--Decommissioning Activities
 
Retained in its entirety by BSEE. Decommissioning activities are the
 responsibility of BSEE, under the authority for regulatory enforcement
 of safety, environment and conservation compliance of the Nation's
 offshore resources.
------------------------------------------------------------------------
                          Subpart R--[Reserved]
------------------------------------------------------------------------
      Subpart S--Safety and Environmental Management Systems (SEMS)
 
Retained in its entirety by BSEE. This subpart addresses operator
 developed SEMS programs; these programs are the responsibility of BSEE,
 under the authority for regulatory enforcement of safety, environment
 and conservation compliance of the Nation's offshore resources.
------------------------------------------------------------------------

Part 251--Geological and Geophysical (G&G) Explorations of the Outer 
Continental Shelf

    This part establishes requirements to conduct G&G activities 
related to oil, gas, and sulphur on unleased lands, or lands under 
lease to a third party. Most of this part will be the responsibility of 
BOEM, under its authority to conduct exploration or scientific research 
activities. Some sections that address drilling will go to BSEE that 
address drilling.

                  Table C--Detailed Table for Part 251
------------------------------------------------------------------------
                                   Implementing
   Current citation and BSEE     bureau and BOEM
   citation (if applicable)        citation (if         Explanation
                                   applicable)
------------------------------------------------------------------------
  PART 251--GEOLOGICAL AND GEOPHYSICAL (G&G) EXPLORATIONS OF THE OUTER
                            CONTINENTAL SHELF
------------------------------------------------------------------------
Sec.   251.1 Definitions......  Both BSEE and      Definitions section,
                                 BOEM, Sec.         the same definitions
                                 551.1.             apply to both
                                                    bureaus.
Sec.   251.2 Purpose of this    Moved to BOEM,     This section
 part.                           Sec.   551.2.      addresses prelease
                                                    G&G activities.
                                                    Prelease activities
                                                    are under the
                                                    authority of BOEM.
Sec.   251.3 Authority and      Both BSEE and      This section
 applicability of this part.     BOEM, Sec.         addresses prelease
                                 551.3.             G&G activities.
                                                    Prelease activities
                                                    are under the
                                                    authority of BOEM.
Sec.   251.4 Types of G&G       Moved to BOEM,     This section
 activities that require         Sec.   551.4.      addresses prelease
 permits or Notices.                                G&G activities.
                                                    Prelease activities
                                                    are under the
                                                    authority of BOEM.
Sec.   251.5 Applying for       Moved to BOEM,     This section
 permits or filing Notices.      Sec.   551.5.      addresses prelease
                                                    G&G activities.
                                                    Prelease activities
                                                    are under the
                                                    authority of BOEM.
Sec.   251.6 Obligations and    Moved to BOEM,     This section
 rights under a permit or a      Sec.   551.6.      addresses prelease
 Notice.                                            G&G activities.
                                                    Prelease activities
                                                    are under the
                                                    authority of BOEM.
Sec.   251.7 Test drilling      Responsibilities   All of paragraph (b)
 activities under a permit.      divided between    regulates drilling
                                 both BSEE and      activities, which
                                 BOEM.              are operations that
                                                    require a permit,
                                                    under the authority
                                                    of BSEE. All of Sec.
                                                      551.7, except
                                                    (b)(6) and (b)(8),
                                                    is under BOEM.
Sec.   251.8 Inspection and     Moved to BOEM,     This section
 reporting requirements for      Sec.   551.8.      addresses prelease
 activities under a permit.                         G&G activities.
                                                    Prelease activities
                                                    are under the
                                                    authority of BOEM.
Sec.   251.9 Temporarily        Moved to BOEM,     This section
 stopping, canceling, or         Sec.   551.9.      addresses prelease
 relinquishing activities                           G&G activities.
 approved under a permit.                           Prelease activities
                                                    are under the
                                                    authority of BOEM.
Sec.   251.10 Penalties and     Moved to BOEM,     This section
 appeals.                        Sec.   551.10.     addresses prelease
                                                    G&G activities.
                                                    Prelease activities
                                                    are under the
                                                    authority of BOEM.
Sec.   251.11 Submission,       Moved to BOEM,     This section
 inspection, and selection of    Sec.   551.11.     addresses prelease
 geological data and                                G&G activities.
 information collected under a                      Prelease activities
 permit and processed by                            are under the
 permittees or third parties.                       authority of BOEM.

[[Page 64446]]

 
Sec.   251.12 Submission,       Moved to BOEM,     This section
 inspection, and selection of    Sec.   551.12.     addresses prelease
 geophysical data and                               G&G activities.
 information collected under a                      Prelease activities
 permit and processed by                            are under the
 permittees or third parties.                       authority of BOEM.
Sec.   251.13 Reimbursement     Moved to BOEM,     This section
 for the costs of reproducing    Sec.   551.13.     addresses prelease
 data and information and                           G&G activities.
 certain processing costs.                          Prelease activities
                                                    are under the
                                                    authority of BOEM.
Sec.   251.14 Protecting and    Moved to BOEM,     This section
 disclosing data and             Sec.   551.14.     addresses prelease
 information submitted to MMS                       G&G activities.
 under a permit.                                    Prelease activities
                                                    are under the
                                                    authority of BOEM.
Sec.   251.15 Authority for     In both BSEE and   This section
 information collection.         BOEM Sec.          establishes the
                                 551.15.            authority for the
                                                    bureaus to collect
                                                    the required
                                                    information from
                                                    lessees and
                                                    operators who
                                                    conduct business on
                                                    the OCS. Information
                                                    collection is
                                                    required in this
                                                    part for aspects
                                                    regulated by both
                                                    BSEE and BOEM.
------------------------------------------------------------------------

Part 252--Outer Continental Shelf (OCS) Oil and Gas Information Program

    Both BOEM and BSEE will have this part in its entirety. Both 
bureaus will be responsible for collecting and maintaining certain data 
and information. This subpart establishes the responsibilities of the 
bureau for protecting and releasing this data.

                  Table D--Detailed Table for Part 252
------------------------------------------------------------------------
                                   Implementing
   Current citation and BSEE     bureau and BOEM
   citation  (if applicable)       citation (if         Explanation
                                   applicable)
------------------------------------------------------------------------
 PART 252--OUTER CONTINENTAL SHELF (OCS) OIL AND GAS INFORMATION PROGRAM
------------------------------------------------------------------------
Sec.   252.1 Purpose..........  In both BSEE and   Both BSEE and BOEM
                                 BOEM Sec.          will collect,
                                 552.1.             maintain, and use
                                                    data collected under
                                                    this program. Both
                                                    bureaus are
                                                    responsible for
                                                    managing the data
                                                    and determining how
                                                    and when the data is
                                                    released.
Sec.   252.2 Definitions......  In both BSEE and   Definitions section.
                                 BOEM Sec.          The same definitions
                                 552.2.             apply to both sets
                                                    of regulations.
Sec.   252.3 Oil and gas data   In both BSEE and   Both BSEE and BOEM
 and information to be           BOEM Sec.          will collect.
 provided for use in the OCS     552.3.
 Oil and Gas Information
 Program.
Sec.   252.4 Summary Report to  In both BSEE and   Both BSEE and BOEM
 affected States.                BOEM Sec.          will collect.
                                 552.4.
Sec.   252.5 Information to be  In both BSEE and   Both BSEE and BOEM
 made available to affected      BOEM Sec.          will collect.
 States.                         552.5.
Sec.   252.6 Freedom of         In both BSEE and   Both BSEE and BOEM
 Information Act requirements.   BOEM Sec.          will collect.
                                 552.6.
Sec.   252.7 Privileged and     In both BSEE and   Both BSEE and BOEM
 proprietary data and            BOEM Sec.          will collect.
 information to be made          552.7.
 available to affected States.
------------------------------------------------------------------------

Part 253--Oil Spill Financial Responsibility for Offshore Facilities--
Moved to BOEM in Its Entirety, Chapter V Part 523

    All financial responsibility functions will be under the authority 
of BOEM, under its mission to manage the development of offshore 
resources in an economically responsible way.

[[Page 64447]]



                  Table E--Detailed Table for Part 253
------------------------------------------------------------------------
                                   Implementing
   Current citation and BSEE     bureau and BOEM
   citation  (if applicable)       citation (if         Explanation
                                   applicable)
------------------------------------------------------------------------
                           Subpart A--General
------------------------------------------------------------------------
Sec.   253.1 What is the        Moved to BOEM,     BOEM is responsible
 purpose of this part?           Sec.   553.1.      for all activities
                                                    related to financial
                                                    assurance. OPA
                                                    financial
                                                    responsibility is
                                                    required of all oil
                                                    handling facilities
                                                    seaward of the
                                                    coastline, whether
                                                    production
                                                    facilities or not
                                                    and whether Federal
                                                    or not.
Sec.   253.3 How are the terms  Moved to BOEM,     BOEM is responsible
 used in this regulation         Sec.   553.3.      for all activities
 defined?                                           related to financial
                                                    assurance.
Sec.   253.5 What is the        Moved to BOEM,     BOEM is responsible
 authority for collecting Oil    Sec.   553.5.      for all activities
 Spill Financial                                    related to financial
 Responsibility (OSFR)                              assurance.
 information?
------------------------------------------------------------------------
               Subpart B--Applicability and Amount of OSFR
------------------------------------------------------------------------
Sec.   253.10 What facilities   Moved to BOEM,     BOEM is responsible
 does this part cover?           Sec.   553.10.     for all activities
                                                    related to financial
                                                    assurance.
Sec.   253.11 Who must          Moved to BOEM,     BOEM is responsible
 demonstrate OSFR?               Sec.   553.11.     for all activities
                                                    related to financial
                                                    assurance.
Sec.   253.12 May I ask MMS     Moved to BOEM,     BOEM is responsible
 for a determination of          Sec.   553.12.     for all activities
 whether I must demonstrate                         related to financial
 OSFR?                                              assurance.
Sec.   253.13 How much OSFR     Moved to BOEM,     BOEM is responsible
 must I demonstrate?             Sec.   553.13.     for all activities
                                                    related to financial
                                                    assurance.
Sec.   253.14 How do I          Moved to BOEM,     BOEM is responsible
 determine the worst case oil-   Sec.   553.14.     for all activities
 spill discharge volume?                            related to financial
                                                    assurance.
Sec.   253.15 What are my       Moved to BOEM,     BOEM is responsible
 general OSFR compliance         Sec.   553.15.     for all activities
 responsibilities?                                  related to financial
                                                    assurance.
------------------------------------------------------------------------
                Subpart C--Methods for Demonstrating OSFR
------------------------------------------------------------------------
Sec.   253.20 What methods may  Moved to BOEM,     BOEM is responsible
 I use to demonstrate OSFR?      Sec.   553.20.     for all activities
                                                    related to financial
                                                    assurance.
Sec.   253.21 How can I use     Moved to BOEM,     BOEM is responsible
 self-insurance as OSFR          Sec.   553.21.     for all activities
 evidence?                                          related to financial
                                                    assurance.
Sec.   253.22 How do I apply    Moved to BOEM,     BOEM is responsible
 to use self-insurance as OSFR   Sec.   553.22.     for all activities
 evidence?                                          related to financial
                                                    assurance.
Sec.   253.23 What information  Moved to BOEM,     BOEM is responsible
 must I submit to support my     Sec.   553.23.     for all activities
 net worth demonstration?                           related to financial
                                                    assurance.
Sec.   253.24 When I submit     Moved to BOEM,     BOEM is responsible
 audited annual financial        Sec.   553.24.     for all activities
 statements to verify my net                        related to financial
 worth, what standards must                         assurance.
 they meet?
Sec.   253.25 What financial    Moved to BOEM,     BOEM is responsible
 test procedures must I use to   Sec.   553.25.     for all activities
 determine the amount of self-                      related to financial
 insurance allowed as OSFR                          assurance.
 evidence based on net worth?
Sec.   253.26 What information  Moved to BOEM,     BOEM is responsible
 must I submit to support my     Sec.   553.26.     for all activities
 unencumbered assets                                related to financial
 demonstration?                                     assurance.
Sec.   253.27 When I submit     Moved to BOEM,     BOEM is responsible
 audited annual financial        Sec.   553.27.     for all activities
 statements to verify my                            related to financial
 unencumbered assets, what                          assurance.
 standards must they meet?
Sec.   253.28 What financial    Moved to BOEM,     BOEM is responsible
 test procedures must I use to   Sec.   553.28.     for all activities
 evaluate the amount of self-                       related to financial
 insurance allowed as OSFR                          assurance.
 evidence based on
 unencumbered assets?
Sec.   253.29 How can I use     Moved to BOEM,     BOEM is responsible
 insurance as OSFR evidence?     Sec.   553.29.     for all activities
                                                    related to financial
                                                    assurance.
Sec.   253.30 How can I use an  Moved to BOEM,     BOEM is responsible
 indemnity as OSFR evidence?     Sec.   553.30.     for all activities
                                                    related to financial
                                                    assurance.
Sec.   253.31 How can I use a   Moved to BOEM,     BOEM is responsible
 surety bond as OSFR evidence?   Sec.   553.31.     for all activities
                                                    related to financial
                                                    assurance.

[[Page 64448]]

 
Sec.   253.32 Are there         Moved to BOEM,     BOEM is responsible
 alternative methods to          Sec.   553.32.     for all activities
 demonstrate OSFR?                                  related to financial
                                                    assurance.
------------------------------------------------------------------------
         Subpart D--Requirements for Submitting OSFR Information
------------------------------------------------------------------------
Sec.   253.40 What OSFR         Moved to BOEM,     BOEM is responsible
 evidence must I submit to       Sec.   553.40.     for all activities
 MMS?                                               related to financial
                                                    assurance.
Sec.   253.41 What terms must   Moved to BOEM,     BOEM is responsible
 I include in my OSFR            Sec.   553.41.     for all activities
 evidence?                                          related to financial
                                                    assurance.
Sec.   253.42 How can I amend   Moved to BOEM,     BOEM is responsible
 my list of COFs?                Sec.   553.42.     for all activities
                                                    related to financial
                                                    assurance.
Sec.   253.43 When is my OSFR   Moved to BOEM,     BOEM is responsible
 demonstration or the            Sec.   553.43.     for all activities
 amendment to my OSFR                               related to financial
 demonstration effective?                           assurance.
Sec.   253.44 [Reserved]......  Sec.   553.44      BOEM is responsible
                                 [Reserved].        for all activities
                                                    related to financial
                                                    assurance.
Sec.   253.45 Where do I send   Moved to BOEM,     BOEM is responsible
 my OSFR evidence?               Sec.   553.45.     for all activities
                                                    related to financial
                                                    assurance.
------------------------------------------------------------------------
                   Subpart E--Revocation and Penalties
------------------------------------------------------------------------
Sec.   253.50 How can MMS       Moved to BOEM,     BOEM is responsible
 refuse or invalidate my OSFR    Sec.   553.50.     for all activities
 evidence?                                          related to financial
                                                    assurance.
Sec.   253.51 What are the      Moved to BOEM,     BOEM is responsible
 penalties for not complying     Sec.   553.51.     for all activities
 with this part?                                    related to financial
                                                    assurance.
------------------------------------------------------------------------
        Subpart F--Claims for Oil-Spill Removal Costs and Damages
------------------------------------------------------------------------
Sec.   253.60 To whom may I     Moved to BOEM,     BOEM is responsible
 present a claim?                Sec.   553.60.     for all activities
                                                    related to financial
                                                    assurance.
Sec.   253.61 When is a         Moved to BOEM,     BOEM is responsible
 guarantor subject to direct     Sec.   553.61.     for all activities
 action for claims?                                 related to financial
                                                    assurance.
Sec.   253.62 What are the      Moved to BOEM,     BOEM is responsible
 designated applicant's          Sec.   553.62.     for all activities
 notification obligations                           related to financial
 regarding a claim?                                 assurance.
Appendix--Appendix to Part      Moved to BOEM,     BOEM is responsible
 253--List of U.S. Geological    Appendix to part   for all activities
 Survey Topographic Maps.        553.               related to financial
                                                    assurance.
------------------------------------------------------------------------

Part 254--Oil-Spill Response Requirements for Facilities Located 
Seaward of the Coast Line--Retained in Its Entirety in BSEE

    All oil-spill response functions will be managed by BSEE under its 
responsibility for enforcement of environmental compliance 
requirements.

                  Table F--Detailed Table for Part 254
------------------------------------------------------------------------
                                   Implementing
   Current citation and BSEE     bureau and BOEM
   citation (if applicable)        citation (if         Explanation
                                   applicable)
------------------------------------------------------------------------
                           Subpart A--General
------------------------------------------------------------------------
Sec.   254.1 Who must submit a  Retained in its    All oil spill related
 spill-response plan?            entirety in        regulations, except
                                 BSEE, chapter II.  for financial
                                                    responsibility, are
                                                    under BSEE, under
                                                    its responsibility
                                                    for oil spill
                                                    response.
Sec.   254.2 When must I        Retained in its    All oil spill related
 submit a response plan?         entirety in        regulations, except
                                 BSEE, chapter II.  for financial
                                                    responsibility, are
                                                    under BSEE, under
                                                    its responsibility
                                                    for oil spill
                                                    response.
Sec.   254.3 May I cover more   Retained in its    All oil spill related
 than one facility in my         entirety in        regulations, except
 response plan?                  BSEE, chapter II.  for financial
                                                    responsibility, are
                                                    under BSEE, under
                                                    its responsibility
                                                    for oil spill
                                                    response.
Sec.   254.4 May I reference    Retained in its    All oil spill related
 other documents in my           entirety in        regulations, except
 response plan?                  BSEE, chapter II.  for financial
                                                    responsibility, are
                                                    under BSEE, under
                                                    its responsibility
                                                    for oil spill
                                                    response.
Sec.   254.5 General response   Retained in its    All oil spill related
 plan requirements.              entirety in        regulations, except
                                 BSEE, chapter II.  for financial
                                                    responsibility, are
                                                    under BSEE, under
                                                    its responsibility
                                                    for oil spill
                                                    response.
Sec.   254.6 Definitions......  Retained in its    All oil spill related
                                 entirety in        regulations, except
                                 BSEE, chapter II.  for financial
                                                    responsibility, are
                                                    under BSEE, under
                                                    its responsibility
                                                    for oil spill
                                                    response.
Sec.   254.7 How do I submit    Retained in its    All oil spill related
 my response plan to the MMS?    entirety in        regulations, except
                                 BSEE, chapter II.  for financial
                                                    responsibility, are
                                                    under BSEE, under
                                                    its responsibility
                                                    for oil spill
                                                    response.

[[Page 64449]]

 
Sec.   254.8 May I appeal       Retained in its    All oil spill related
 decisions under this part?      entirety in        regulations, except
                                 BSEE, chapter II.  for financial
                                                    responsibility, are
                                                    under BSEE, under
                                                    its responsibility
                                                    for oil spill
                                                    response.
Sec.   254.9 Authority for      Retained in its    All oil spill related
 information collection.         entirety in        regulations, except
                                 BSEE, chapter II.  for financial
                                                    responsibility, are
                                                    under BSEE, under
                                                    its responsibility
                                                    for oil spill
                                                    response.
------------------------------------------------------------------------
     Subpart B--Oil-Spill Response Plans for Outer Continental Shelf
                               Facilities
------------------------------------------------------------------------
Sec.   254.20 Purpose.........  Retained in its    All oil spill related
                                 entirety in        regulations, except
                                 BSEE, chapter II.  for financial
                                                    responsibility, are
                                                    under BSEE, under
                                                    its responsibility
                                                    for oil spill
                                                    response.
Sec.   254.21 How must I        Retained in its    All oil spill related
 format my response plan?        entirety in        regulations, except
                                 BSEE, chapter II.  for financial
                                                    responsibility, are
                                                    under BSEE, under
                                                    its responsibility
                                                    for oil spill
                                                    response.
Sec.   254.22 What information  Retained in its    All oil spill related
 must I include in the           entirety in        regulations, except
 ``Introduction and plan         BSEE, chapter II.  for financial
 contents'' section?                                responsibility, are
                                                    under BSEE, under
                                                    its responsibility
                                                    for oil spill
                                                    response.
Sec.   254.23 What information  Retained in its    All oil spill related
 must I include in the           entirety in        regulations, except
 ``Emergency response action     BSEE, chapter II.  for financial
 plan'' section?                                    responsibility, are
                                                    under BSEE, under
                                                    its responsibility
                                                    for oil spill
                                                    response.
Sec.   254.24 What information  Retained in its    All oil spill related
 must I include in the           entirety in        regulations, except
 ``Equipment inventory''         BSEE, chapter II.  for financial
 appendix?                                          responsibility, are
                                                    under BSEE, under
                                                    its responsibility
                                                    for oil spill
                                                    response.
Sec.   254.25 What information  Retained in its    All oil spill related
 must I include in the           entirety in        regulations, except
 ``Contractual agreements''      BSEE, chapter II.  for financial
 appendix?                                          responsibility, are
                                                    under BSEE, under
                                                    its responsibility
                                                    for oil spill
                                                    response.
Sec.   254.26 What information  Retained in its    All oil spill related
 must I include in the ``Worst   entirety in        regulations, except
 case discharge scenario''       BSEE, chapter II.  for financial
 appendix?                                          responsibility, are
                                                    under BSEE, under
                                                    its responsibility
                                                    for oil spill
                                                    response.
Sec.   254.27 What information  Retained in its    All oil spill related
 must I include in the           entirety in        regulations, except
 ``Dispersant use plan''         BSEE, chapter II.  for financial
 appendix?                                          responsibility, are
                                                    under BSEE, under
                                                    its responsibility
                                                    for oil spill
                                                    response.
Sec.   254.28 What information  Retained in its    All oil spill related
 must I include in the ``In      entirety in        regulations, except
 situ burning plan'' appendix?   BSEE, chapter II.  for financial
                                                    responsibility, are
                                                    under BSEE, under
                                                    its responsibility
                                                    for oil spill
                                                    response.
Sec.   254.29 What information  Retained in its    All oil spill related
 must I include in the           entirety in        regulations, except
 ``Training and drills''         BSEE, chapter II.  for financial
 appendix?                                          responsibility, are
                                                    under BSEE, under
                                                    its responsibility
                                                    for oil spill
                                                    response.
Sec.   254.30 When must I       Retained in its    All oil spill related
 revise my response plan?        entirety in        regulations, except
                                 BSEE, chapter II.  for financial
                                                    responsibility, are
                                                    under BSEE, under
                                                    its responsibility
                                                    for oil spill
                                                    response.
------------------------------------------------------------------------
 Subpart C--Related Requirements for Outer Continental Shelf Facilities
------------------------------------------------------------------------
Sec.   254.40 Records.........  Retained in its    All oil spill related
                                 entirety in        regulations, except
                                 BSEE, chapter II.  for financial
                                                    responsibility, are
                                                    under BSEE, under
                                                    its responsibility
                                                    for oil spill
                                                    response.
Sec.   254.41 Training your     Retained in its    All oil spill related
 response personnel.             entirety in        regulations, except
                                 BSEE, chapter II.  for financial
                                                    responsibility, are
                                                    under BSEE, under
                                                    its responsibility
                                                    for oil spill
                                                    response.
Sec.   254.42 Exercises for     Retained in its    All oil spill related
 your response personnel and     entirety in        regulations, except
 equipment.                      BSEE, chapter II.  for financial
                                                    responsibility, are
                                                    under BSEE, under
                                                    its responsibility
                                                    for oil spill
                                                    response.
Sec.   254.43 Maintenance and   Retained in its    All oil spill related
 periodic inspection of          entirety in        regulations, except
 response equipment.             BSEE, chapter II.  for financial
                                                    responsibility, are
                                                    under BSEE, under
                                                    its responsibility
                                                    for oil spill
                                                    response.
Sec.   254.44 Calculating       Retained in its    All oil spill related
 response equipment effective    entirety in        regulations, except
 daily recovery capacities.      BSEE, chapter II.  for financial
                                                    responsibility, are
                                                    under BSEE, under
                                                    its responsibility
                                                    for oil spill
                                                    response.
Sec.   254.45 Verifying the     Retained in its    All oil spill related
 capabilities of your response   entirety in        regulations, except
 equipment.                      BSEE, chapter II.  for financial
                                                    responsibility, are
                                                    under BSEE, under
                                                    its responsibility
                                                    for oil spill
                                                    response.
Sec.   254.46 Whom do I notify  Retained in its    All oil spill related
 if an oil spill occurs?         entirety in        regulations, except
                                 BSEE, chapter II.  for financial
                                                    responsibility, are
                                                    under BSEE, under
                                                    its responsibility
                                                    for oil spill
                                                    response.
Sec.   254.47 Determining the   Retained in its    All oil spill related
 volume of oil of your worst     entirety in        regulations, except
 case discharge scenario.        BSEE, chapter II.  for financial
                                                    responsibility, are
                                                    under BSEE, under
                                                    its responsibility
                                                    for oil spill
                                                    response.
------------------------------------------------------------------------
  Subpart D--Oil-Spill Response Requirements for Facilities Located in
                 State Waters Seaward of the Coast Line
------------------------------------------------------------------------
Sec.   254.50 Spill response    Retained in its    All oil spill related
 plans for facilities located    entirety in        regulations, except
 in State waters seaward of      BSEE, chapter II.  for financial
 the coast line.                                    responsibility, are
                                                    under BSEE, under
                                                    its responsibility
                                                    for oil spill
                                                    response.
Sec.   254.51 Modifying an      Retained in its    All oil spill related
 existing OCS response plan.     entirety in        regulations, except
                                 BSEE, chapter II.  for financial
                                                    responsibility, are
                                                    under BSEE, under
                                                    its responsibility
                                                    for oil spill
                                                    response.
Sec.   254.52 Following the     Retained in its    All oil spill related
 format for an OCS response      entirety in        regulations, except
 plan.                           BSEE, chapter II.  for financial
                                                    responsibility, are
                                                    under BSEE, under
                                                    its responsibility
                                                    for oil spill
                                                    response.

[[Page 64450]]

 
Sec.   254.53 Submitting a      Retained in its    All oil spill related
 response plan developed under   entirety in        regulations, except
 State requirements.             BSEE, chapter II.  for financial
                                                    responsibility, are
                                                    under BSEE, under
                                                    its responsibility
                                                    for oil spill
                                                    response.
Sec.   254.54 Spill prevention  Retained in its    All oil spill related
 for facilities located in       entirety in        regulations, except
 State waters seaward of the     BSEE, chapter II.  for financial
 coast line.                                        responsibility, are
                                                    under BSEE, under
                                                    its responsibility
                                                    for oil spill
                                                    response.
------------------------------------------------------------------------

Part 256--Leasing of Sulphur or Oil and Gas in the Outer Continental 
Shelf

    This part establishes leasing requirements for sulphur, oil, and 
natural gas. Most of this part will be under the responsibility of BOEM 
under its authority to manage the development of the Nation's offshore 
resources in an environmentally and economically responsible way. Some 
sections will go to BSEE that address lease extensions by drilling and 
suspensions of operations or production.

                  Table G--Detailed Table for Part 256
------------------------------------------------------------------------
                                   Implementing
   Current citation and BSEE     bureau and BOEM
   citation  (if applicable)       citation (if         Explanation
                                   applicable)
------------------------------------------------------------------------
  Subpart A--Outer Continental Shelf Oil, Gas, and Sulphur Management,
                                 General
------------------------------------------------------------------------
Sec.   256.0 Authority for      Moved to BOEM,     This section
 information collection.         Sec.   556.0.      addresses leasing
                                                    activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
Sec.   256.1 Purpose..........  Moved to BOEM,     This section
                                 Sec.   556.1,      addresses leasing
                                 retained purpose   activities on the
                                 except for right-  OCS that are under
                                 of-way grant       the authority of
                                 clause; under      BOEM.
                                 BSEE retained
                                 right-of-way
                                 grant clause.
Sec.   256.2 Policy...........  Moved to BOEM,     This section
                                 Sec.   556.2.      addresses leasing
                                                    activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
Sec.   256.4 Authority........  Moved to BOEM,     This section
                                 Sec.   556.4.      addresses leasing
                                                    activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
Sec.   256.5 Definitions......  Moved to BOEM,     This section
                                 Sec.   556.5.      addresses leasing
                                                    activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
Sec.   256.7 Cross references.  Both BSEE and      This section contains
                                 BOEM Sec.          cross references
                                 556.7.             that are pertinent
                                                    to both BSEE and
                                                    BOEM activities.
Sec.   256.8 Leasing maps and   Moved to BOEM,     This section
 diagrams.                       Sec.   556.8.      addresses leasing
                                                    activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
Sec.   256.10 Information to    Moved to BOEM,     This section
 States.                         Sec.   556.10.     addresses leasing
                                                    activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
Sec.   256.11 Helium..........  Moved to BOEM,     This section
                                 Sec.   556.11.     addresses leasing
                                                    activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
Sec.   256.12 Supplemental      Moved to BOEM,     This section
 sales.                          Sec.   556.12.     addresses leasing
                                                    activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
------------------------------------------------------------------------
                 Subpart B--Oil and Gas Leasing Program
------------------------------------------------------------------------
Sec.   256.16 Receipt and       Moved to BOEM,     This section
 consideration of nominations;   Sec.   556.16.     addresses leasing
 public notice and                                  activities on the
 participation.                                     OCS that are under
                                                    the authority of
                                                    BOEM.
Sec.   256.17 Review by State   Moved to BOEM,     This section
 and local governments and       Sec.   556.17.     addresses leasing
 other persons.                                     activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
Sec.   256.19 Periodic          Moved to BOEM,     This section
 consultation with interested    Sec.   556.19.     addresses leasing
 parties.                                           activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
Sec.   256.20 Consideration of  Moved to BOEM,     This section
 coastal zone management         Sec.   556.20.     addresses leasing
 program.                                           activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
------------------------------------------------------------------------
                Subpart C--Reports From Federal Agencies
------------------------------------------------------------------------
Sec.   256.22 General.........  Moved to BOEM,     This section
                                 Sec.   556.22.     addresses leasing
                                                    activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
------------------------------------------------------------------------
             Subpart D--Call for Information and Nominations
------------------------------------------------------------------------
Sec.   256.23 Information on    Moved to BOEM,     This section
 areas.                          Sec.   556.23.     addresses leasing
                                                    activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
Sec.   256.25 Areas near        Moved to BOEM,     This section
 coastal states.                 Sec.   556.25.     addresses leasing
                                                    activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
------------------------------------------------------------------------

[[Page 64451]]

 
              Subpart E--Area Identification and Tract Size
------------------------------------------------------------------------
Sec.   256.26 General.........  Moved to BOEM,     This section
                                 Sec.   556.26.     addresses leasing
                                                    activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
Sec.   256.28 Tract size......  Moved to BOEM,     This section
                                 Sec.   556.28.     addresses leasing
                                                    activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
------------------------------------------------------------------------
                         Subpart F--Lease Sales
------------------------------------------------------------------------
Sec.   256.29 Proposed notice   Moved to BOEM,     This section
 of sale.                        Sec.   556.29.     addresses leasing
                                                    activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
Sec.   256.31 State comments..  Moved to BOEM,     This section
                                 Sec.   556.31.     addresses leasing
                                                    activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
Sec.   256.32 Notice of sale..  Moved to BOEM,     This section
                                 Sec.   556.32.     addresses leasing
                                                    activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
------------------------------------------------------------------------
                      Subpart G--Issuance of Leases
------------------------------------------------------------------------
Sec.   256.35 Qualifications    Moved to BOEM,     This section
 of lessees.                     Sec.   556.35.     addresses leasing
                                                    activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
Sec.   256.37 Lease term......  Moved to BOEM,     This section
                                 Sec.   556.37.     addresses leasing
                                                    activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
Sec.   256.38 Joint bidding     Moved to BOEM,     This section
 provisions.                     Sec.   556.38.     addresses leasing
                                                    activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
Sec.   256.40 Definitions.....  Moved to BOEM,     This section
                                 Sec.   556.40.     addresses leasing
                                                    activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
Sec.   256.41 Joint bidding     Moved to BOEM,     This section
 requirements.                   Sec.   556.41.     addresses leasing
                                                    activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
Sec.   256.43 Chargeability     Moved to BOEM,     This section
 for production.                 Sec.   556.43.     addresses leasing
                                                    activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
Sec.   256.44 Bids              Moved to BOEM,     This section
 disqualified.                   Sec.   556.44.     addresses leasing
                                                    activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
Sec.   256.46 Submission of     Moved to BOEM,     This section
 bids.                           Sec.   556.46.     addresses leasing
                                                    activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
Sec.   256.47 Award of leases.  Moved to BOEM,     This section
                                 Sec.   556.47.     addresses leasing
                                                    activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
Sec.   256.49 Lease form......  Moved to BOEM,     This section
                                 Sec.   556.49.     addresses leasing
                                                    activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
Sec.   256.50 Dating of leases  Moved to BOEM,     This section
                                 Sec.   556.50.     addresses leasing
                                                    activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
------------------------------------------------------------------------
               Subpart H--Rentals and Royalties [Reserved]
------------------------------------------------------------------------
                           Subpart I--Bonding
------------------------------------------------------------------------
Sec.   256.52 Bond              Moved to BOEM,     This section
 requirements for an oil and     Sec.   556.52.     addresses leasing
 gas or sulphur lease.                              activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
Sec.   256.53 Additional bonds  Moved to BOEM,     This section
                                 Sec.   556.53.     addresses leasing
                                                    activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
Sec.   256.54 General           Moved to BOEM,     This section
 requirements for bonds.         Sec.   556.54.     addresses leasing
                                                    activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
Sec.   256.55 Lapse of bond...  Moved to BOEM,     This section
                                 Sec.   556.55.     addresses leasing
                                                    activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
Sec.   256.56 Lease-specific    Moved to BOEM,     This section
 abandonment accounts.           Sec.   556.56.     addresses leasing
                                                    activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
Sec.   256.57 Using a third-    Moved to BOEM,     This section
 party guarantee instead of a    Sec.   556.57.     addresses leasing
 bond.                                              activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
Sec.   256.58 Termination of    Moved to BOEM,     This section
 the period of liability and     Sec.   556.58.     addresses leasing
 cancellation of a bond.                            activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
Sec.   256.59 Forfeiture of     Moved to BOEM,     This section
 bonds and/or other securities.  Sec.   556.59.     addresses leasing
                                                    activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
------------------------------------------------------------------------
            Subpart J--Assignments, Transfers, and Extensions
------------------------------------------------------------------------
Sec.   256.62 Assignment of     Moved to BOEM,     This section
 lease or interest in lease.     Sec.   556.62.     addresses leasing
                                                    activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
Sec.   256.63 Service fees....  Moved to BOEM,     This section
                                 Sec.   556.63.     addresses leasing
                                                    activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
Sec.   256.64 How to file       Moved to BOEM,     This section
 transfers.                      Sec.   556.64.     addresses leasing
                                                    activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.

[[Page 64452]]

 
Sec.   256.65 Attorney General  Moved to BOEM,     This section
 review.                         Sec.   556.65.     addresses leasing
                                                    activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
Sec.   256.67 Separate filings  Moved to BOEM,     This section
 for assignments.                Sec.   556.67.     addresses leasing
                                                    activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
Sec.   256.68 Effect of         Moved to BOEM,     This section
 assignment of a particular      Sec.   556.68.     addresses leasing
 tract.                                             activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
Sec.   256.70 Extension of      Both BSEE and      Needed by both
 lease by drilling or well       BOEM Sec.          agencies.
 reworking operations.           556.70.
Sec.   256.71 Directional       Both BSEE and      Needed by both
 drilling.                       BOEM Sec.          agencies.
                                 556.71.
Sec.   256.72 Compensatory      Both BSEE and      Needed by both
 payments as production.         BOEM Sec.          agencies.
                                 556.72.
Sec.   256.73 Effect of         Retained by BSEE.  This section
 suspensions on lease term.                         addresses
                                                    enforcement of
                                                    suspension
                                                    activities on the
                                                    OCS that is under
                                                    the authority of
                                                    BSEE. Beyond the
                                                    primary lease term,
                                                    BSEE's oversight
                                                    over operations and
                                                    production and
                                                    suspensions thereof
                                                    determine the lease
                                                    term.
------------------------------------------------------------------------
                    Subpart K--Termination of Leases
------------------------------------------------------------------------
Sec.   256.76 Relinquishment    Moved to BOEM,     This section
 of leases or parts of leases.   Sec.   556.76.     addresses leasing
                                                    administration on
                                                    the OCS that are
                                                    under the authority
                                                    of BOEM.
Sec.   256.77 Cancellation of   Both BSEE and      BOEM is authorized to
 leases.                         BOEM, Sec.         cancel leases. BSEE
                                 556.77.            has the authority to
                                                    initiate lease
                                                    cancellation.
------------------------------------------------------------------------
                       Subpart L--Section 6 Leases
------------------------------------------------------------------------
Sec.   256.79 Effect of         Both BSEE and      Needed by both
 regulations on lease.           BOEM Sec.          agencies.
                                 556.79.
Sec.   256.80 Leases of other   Moved to BOEM,     This section
 minerals.                       Sec.   556.80.     addresses leasing
                                                    administration on
                                                    the OCS that are
                                                    under the authority
                                                    of BOEM.
------------------------------------------------------------------------
                           Subpart M--Studies
------------------------------------------------------------------------
Sec.   256.82 Environmental     Moved to BOEM,     This section
 studies.                        Sec.   556.82.     addresses leasing
                                                    activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
------------------------------------------------------------------------
   Subpart N--Bonus or Royalty Credits for Exchange of Certain Leases
------------------------------------------------------------------------
                            Offshore Florida
------------------------------------------------------------------------
Sec.   256.90 Which leases may  Moved to BOEM,     This section
 I exchange for a bonus or       Sec.   556.90.     addresses leasing
 royalty credit?                                    activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
Sec.   256.91 How much bonus    Moved to BOEM,     This section
 or royalty credit will MMS      Sec.   556.91.     addresses leasing
 grant in exchange for a                            activities on the
 lease?                                             OCS that are under
                                                    the authority of
                                                    BOEM.
Sec.   256.92 What must I do    Moved to BOEM,     This section
 to obtain a bonus or royalty    Sec.   556.92.     addresses leasing
 credit?                                            activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
Sec.   256.93 How is the bonus  Moved to BOEM,     This section
 or royalty credit allocated     Sec.   556.93.     addresses leasing
 among multiple lease owners?                       activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
Sec.   256.94 How may I use     Moved to BOEM,     This section
 the bonus or royalty credit?    Sec.   556.94.     addresses leasing
                                                    activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
Sec.   256.95 How do I          Moved to BOEM,     This section
 transfer a bonus or royalty     Sec.   556.95.     addresses leasing
 credit to another person?                          activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
APPENDIX A PART 256--Appendix   Moved to BOEM,     This section
 A to Part 256--Oil and Gas      APPENDIX A PART    addresses leasing
 Cash Bonus Bid.                 556.               activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
------------------------------------------------------------------------

Part 259--Mineral Leasing: Definitions--Moved to BOEM in Its Entirety, 
Chapter V Part 559

[[Page 64453]]



                  Table H--Detailed Table for Part 259
------------------------------------------------------------------------
                                   Implementing
   Current citation and BSEE     bureau and BOEM
   citation  (if applicable)       citation (if         Explanation
                                   applicable)
------------------------------------------------------------------------
Sec.   259.001 Purpose and      Moved to BOEM,     This section
 scope.                          Sec.   559.001.    addresses
                                                    definitions used in
                                                    lease administration
                                                    under the authority
                                                    of BOEM.
Sec.   259.002 Definitions....  Moved to BOEM,     This section used in
                                 Sec.   559.002.    lease administration
                                                    under the authority
                                                    of BOEM.
------------------------------------------------------------------------

Part 260--Outer Continental Shelf Oil and Gas Leasing--Moved to BOEM in 
Its Entirety, Chapter V, Part 560

    BOEM is responsible for lease sales, bidding systems, the 
regulatory oversight of incentive-based royalty relief and establishing 
royalty relief thresholds.

                  Table I--Detailed Table for Part 260
------------------------------------------------------------------------
                                   Implementing
   Current citation and BSEE     bureau and BOEM
   citation (if applicable)        citation (if         Explanation
                                   applicable)
------------------------------------------------------------------------
                      Subpart A--General Provisions
------------------------------------------------------------------------
Sec.   260.1 What is the        Moved to BOEM,     This section
 purpose of this part?           Sec.   560.1.      addresses leasing
                                                    activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
Sec.   260.2 What definitions   Moved to BOEM,     This section
 apply to this part?             Sec.   560.2.      addresses leasing
                                                    activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
Sec.   260.3 What is MMS's      Moved to BOEM,     This section
 authority to collect            Sec.   560.3.      addresses leasing
 information?                                       activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
------------------------------------------------------------------------
                       Subpart B--Bidding Systems
------------------------------------------------------------------------
Sec.   260.101 What is the      Moved to BOEM,     This section
 purpose of this subpart?        Sec.   560.101.    addresses leasing
                                                    activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
Sec.   260.102 What             Moved to BOEM,     This section
 definitions apply to this       Sec.   560.102.    addresses leasing
 subpart?                                           activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
Sec.   260.110 What bidding     Moved to BOEM,     This section
 systems may MMS use?            Sec.   560.110.    addresses leasing
                                                    activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
Sec.   260.111 What conditions  Moved to BOEM,     This section
 apply to the bidding systems    Sec.   560.111.    addresses leasing
 that MMS uses?                                     activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
Sec.   260.112 How do royalty   Moved to BOEM,     This section
 suspension volumes apply to     Sec.   560.112.    addresses leasing
 eligible leases?                                   activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
Sec.   260.113 When does an     Moved to BOEM,     This section
 eligible lease qualify for a    Sec.   560.113.    addresses leasing
 royalty suspension volume?                         activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
Sec.   260.114 How does MMS     Moved to BOEM,     This section
 assign and monitor royalty      Sec.   560.114.    addresses leasing
 suspension volumes for                             activities on the
 eligible leases?                                   OCS that are under
                                                    the authority of
                                                    BOEM.
Sec.   260.115 How long will a  Moved to BOEM,     This section
 royalty suspension volume for   Sec.   560.115.    addresses leasing
 an eligible lease be                               activities on the
 effective?                                         OCS that are under
                                                    the authority of
                                                    BOEM.
Sec.   260.116 How do I         Moved to BOEM,     This section
 measure natural gas             Sec.   560.116.    addresses leasing
 production on my eligible                          activities on the
 lease?                                             OCS that are under
                                                    the authority of
                                                    BOEM.
Sec.   260.120 How does         Moved to BOEM,     This section
 royalty suspension apply to     Sec.   560.120.    addresses leasing
 leases issued in a sale held                       activities on the
 after November 2000?                               OCS that are under
                                                    the authority of
                                                    BOEM.
Sec.   260.121 When does a      Moved to BOEM,     This section
 lease issued in a sale held     Sec.   560.121.    addresses leasing
 after November 2000 get a                          activities on the
 royalty suspension?                                OCS that are under
                                                    the authority of
                                                    BOEM.
Sec.   260.122 How long will a  Moved to BOEM,     This section
 royalty suspension volume be    Sec.   560.122.    addresses leasing
 effective for a lease issued                       activities on the
 in a sale held after November                      OCS that are under
 2000?                                              the authority of
                                                    BOEM.
Sec.   260.123 How do I         Moved to BOEM,     This section
 measure natural gas             Sec.   560.123.    addresses leasing
 production for a lease issued                      activities on the
 in a sale held after November                      OCS that are under
 2000?                                              the authority of
                                                    BOEM.

[[Page 64454]]

 
Sec.   260.124 How will         Moved to BOEM,     This section
 royalty suspension apply if     Sec.   560.124.    addresses leasing
 MMS assigns a lease issued in                      activities on the
 a sale held after November                         OCS that are under
 2000 to a field that has a                         the authority of
 pre-Act lease?                                     BOEM.
Sec.   260.130 What criteria    Moved to BOEM,     This section
 does MMS use for selecting      Sec.   560.130.    addresses leasing
 bidding systems and bidding                        activities on the
 system components?                                 OCS that are under
                                                    the authority of
                                                    BOEM.
------------------------------------------------------------------------
                          Subpart C--[Reserved]
------------------------------------------------------------------------
                        Subpart D--Joint Bidding
------------------------------------------------------------------------
Sec.   260.301 What is the      Moved to BOEM,     This section
 purpose of this subpart?        Sec.   560.301.    addresses leasing
                                                    activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
Sec.   260.302 What             Moved to BOEM,     This section
 definitions apply to this       Sec.   560.302.    addresses leasing
 subpart?                                           activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
Sec.   260.303 What are the     Moved to BOEM,     This section
 joint bidding requirements?     Sec.   560.303.    addresses leasing
                                                    activities on the
                                                    OCS that are under
                                                    the authority of
                                                    BOEM.
------------------------------------------------------------------------

Part 270--Nondiscrimination in the Outer Continental Shelf

    Both BOEM and BSEE will have this part in its entirety.

                  Table J--Detailed Table for Part 270
------------------------------------------------------------------------
                                   Implementing
   Current citation and BSEE     bureau and BOEM
   citation  (if applicable)       citation (if         Explanation
                                   applicable)
------------------------------------------------------------------------
Sec.   270.1 Purpose..........  Revised in both    This section
                                 BSEE and BOEM      addresses the
                                 Sec.   570.1.      nondiscrimination on
                                                    the OCS provisions
                                                    that are relevant to
                                                    the activities
                                                    regulated by both
                                                    BSEE and BOEM.
Sec.   270.2 Application of     Revised in both    This section
 this part.                      BSEE and BOEM      addresses the
                                 Sec.   570.2.      nondiscrimination on
                                                    the OCS provisions
                                                    that are under the
                                                    authority of both
                                                    BSEE and BOEM.
Sec.   270.3 Definitions......  Revised in both    This section
                                 BSEE and BOEM      addresses the
                                 Sec.   570.3.      nondiscrimination on
                                                    the OCS provisions
                                                    that are under the
                                                    authority of both
                                                    BSEE and BOEM.
Sec.   270.4 Discrimination     Revised in both    This section
 prohibited.                     BSEE and BOEM      addresses the
                                 Sec.   570.4.      nondiscrimination on
                                                    the OCS provisions
                                                    that are under the
                                                    authority of both
                                                    BSEE and BOEM.
Sec.   270.5 Complaint........  Revised in both    This section
                                 BSEE and BOEM      addresses the
                                 Sec.   570.5.      nondiscrimination on
                                                    the OCS provisions
                                                    that are under the
                                                    authority of both
                                                    BSEE and BOEM.
Sec.   270.6 Process..........  Revised in both    This section
                                 BSEE and BOEM      addresses the
                                 Sec.   570.6.      nondiscrimination on
                                                    the OCS provisions
                                                    that are under the
                                                    authority of both
                                                    BSEE and BOEM.
Sec.   270.7 Remedies.........  Revised in both    This section
                                 BSEE and BOEM      addresses the
                                 Sec.   570.7.      nondiscrimination on
                                                    the OCS provisions
                                                    that are under the
                                                    authority of both
                                                    BSEE and BOEM.
------------------------------------------------------------------------

    Part 280--Prospecting for Minerals Other Than Oil, Gas, and Sulphur 
on the Outer Continental Shelf--Moved to BOEM in Its Entirety, Chapter 
V, Part 580
    BOEM is responsible for regulating prospecting activities or 
scientific research activities on the OCS related to hard minerals on 
unleased lands or on lands under lease to a third party.

                  Table K--Detailed Table for Part 280
------------------------------------------------------------------------
 Current citation and    Implementing bureau
   BSEE citation (if    and BOEM citation (if         Explanation
      applicable)            applicable)
------------------------------------------------------------------------
                     Subpart A--General Information
------------------------------------------------------------------------
Sec.   280.1 What       Moved to BOEM, Sec.    This section addresses
 definitions apply to    580.1.                 activities within the
 this part?                                     scope of oil, gas, and
                                                sulphur prospecting on
                                                the OCS under BOEM.
Sec.   280.2 What is    Moved to BOEM, Sec.    This section addresses
 the purpose of this     580.2.                 activities within the
 part?                                          scope of oil, gas and
                                                sulphur prospecting on
                                                the OCS under BOEM.

[[Page 64455]]

 
Sec.   280.3 What       Moved to BOEM, Sec.    This section addresses
 requirements must I     580.3.                 activities within the
 follow when I conduct                          scope of oil, gas, and
 prospecting or                                 sulphur prospecting on
 research activities?                           the OCS under BOEM.
Sec.   280.4 What       Moved to BOEM, Sec.    This section addresses
 activities are not      580.4.                 activities within the
 covered by this part?                          scope of oil, gas, and
                                                sulphur prospecting on
                                                the OCS under BOEM.
------------------------------------------------------------------------
          Subpart B--How To Apply for a Permit or File a Notice
------------------------------------------------------------------------
Sec.   280.10 What      Moved to BOEM, Sec.    This section addresses
 must I do before I      580.10.                activities within the
 may conduct                                    scope of oil, gas, and
 prospecting                                    sulphur prospecting on
 activities?                                    the OCS under BOEM.
Sec.   280.11 What      Moved to BOEM, Sec.    This section addresses
 must I do before I      580.11.                activities within the
 may conduct                                    scope of oil, gas, and
 scientific research?                           sulphur prospecting on
                                                the OCS under BOEM.
Sec.   280.12 What      Moved to BOEM, Sec.    This section addresses
 must I include in my    580.12.                activities within the
 application or                                 scope of oil, gas, and
 notification?                                  sulphur prospecting on
                                                the OCS under BOEM.
Sec.   280.13 Where     Moved to BOEM, Sec.    This section addresses
 must I send my          580.13.                activities within the
 application or                                 scope of oil, gas, and
 notification?                                  sulphur prospecting on
                                                the OCS under BOEM.
------------------------------------------------------------------------
                 Subpart C--Obligations Under This Part
------------------------------------------------------------------------
Sec.   280.20 What      Moved to BOEM, Sec.    This section addresses
 must I not do in        580.20.                activities within the
 conducting Geological                          scope of oil, gas, and
 and Geophysical (G&G)                          sulphur prospecting on
 prospecting or                                 the OCS under BOEM.
 scientific research?
Sec.   280.21 What      Moved to BOEM, Sec.    This section addresses
 must I do in            580.21.                activities within the
 conducting G&G                                 scope of oil, gas, and
 prospecting or                                 sulphur prospecting on
 scientific research?                           the OCS under BOEM.
Sec.   280.22 What      Moved to BOEM, Sec.    This section addresses
 must I do when          580.22.                activities within the
 seeking approval for                           scope of oil, gas, and
 modifications?                                 sulphur prospecting on
                                                the OCS under BOEM.
Sec.   280.23 How must  Moved to BOEM, Sec.    This section addresses
 I cooperate with        580.23.                activities within the
 inspection                                     scope of oil, gas, and
 activities?                                    sulphur prospecting on
                                                the OCS under BOEM.
Sec.   280.24 What      Moved to BOEM, Sec.    This section addresses
 reports must I file?    580.24.                activities within the
                                                scope of oil, gas, and
                                                sulphur prospecting on
                                                the OCS under BOEM.
Sec.   280.25 When may  Moved to BOEM, Sec.    This section addresses
 MMS require me to       580.25.                activities within the
 stop activities under                          scope of oil, gas, and
 this part?                                     sulphur prospecting on
                                                the OCS under BOEM.
Sec.   280.26 When may  Moved to BOEM, Sec.    This section addresses
 I resume activities?    580.26.                activities within the
                                                scope of oil, gas, and
                                                sulphur prospecting on
                                                the OCS under BOEM.
Sec.   280.27 When may  In both BSEE and       This section addresses
 MMS cancel my permit?   BOEM, Sec.   580.27.   activities within the
                                                scope of oil, gas, and
                                                sulphur prospecting on
                                                the OCS under BOEM.
Sec.   280.28 May I     In both BSEE and       This section addresses
 relinquish my permit?   BOEM, Sec.   580.28.   activities within the
                                                scope of oil, gas, and
                                                sulphur prospecting on
                                                the OCS under BOEM.
Sec.   280.29 Will MMS  Moved to BOEM, Sec.    This section addresses
 monitor the             580.29.                activities within the
 environmental effects                          scope of oil, gas, and
 of my activity?                                sulphur prospecting on
                                                the OCS under BOEM.
Sec.   280.30 What      Moved to BOEM, Sec.    This section addresses
 activities will not     580.30.                activities within the
 require environmental                          scope of oil, gas, and
 analysis?                                      sulphur prospecting on
                                                the OCS under BOEM.
Sec.   280.31 Whom      Moved to BOEM, Sec.    This section addresses
 will MMS notify about   580.31.                activities within the
 environmental issues?                          scope of oil, gas, and
                                                sulphur prospecting on
                                                the OCS under BOEM.
Sec.   280.32 What      Moved to BOEM, Sec.    This section addresses
 penalties may I be      580.32.                activities within the
 subject to?                                    scope of oil, gas, and
                                                sulphur prospecting on
                                                the OCS under BOEM.
Sec.   280.33 How can   Moved to BOEM, Sec.    This section addresses
 I appeal a penalty?     580.33.                activities within the
                                                scope of oil, gas, and
                                                sulphur prospecting on
                                                the OCS under BOEM.
Sec.   280.34 How can   Moved to BOEM, Sec.    This section addresses
 I appeal an order or    580.34.                activities within the
 decision?                                      scope of oil, gas, and
                                                sulphur prospecting on
                                                the OCS under BOEM.
------------------------------------------------------------------------
                      Subpart D--Data Requirements
------------------------------------------------------------------------
Sec.   280.40 When do   Moved to BOEM, Sec.    This section addresses
 I notify MMS that       580.40.                activities within the
 geological data and                            scope of oil, gas, and
 information are                                sulphur prospecting on
 available for                                  the OCS under BOEM.
 submission,
 inspection, and
 selection?
Sec.   280.41 What      Moved to BOEM, Sec.    This section addresses
 types of geological     580.41.                activities within the
 data and information                           scope of oil, gas, and
 must I submit to MMS?                          sulphur prospecting on
                                                the OCS under BOEM.
Sec.   280.42 When      Moved to BOEM, Sec.    This section addresses
 geological data and     580.42.                activities within the
 information are                                scope of oil, gas, and
 obtained by a third                            sulphur prospecting on
 party, what must we                            the OCS under BOEM.
 both do?

[[Page 64456]]

 
Sec.   280.50 When do   Moved to BOEM, Sec.    This section addresses
 I notify MMS that       580.50.                activities within the
 geophysical data and                           scope of oil, gas, and
 information are                                sulphur prospecting on
 available for                                  the OCS under BOEM.
 submission,
 inspection, and
 selection?
Sec.   280.51 What      Moved to BOEM, Sec.    This section addresses
 types of geophysical    580.51.                activities within the
 data and information                           scope of oil, gas, and
 must I submit to MMS?                          sulphur prospecting on
                                                the OCS under BOEM.
Sec.   280.52 When      Moved to BOEM, Sec.    This section addresses
 geophysical data and    580.52.                activities within the
 information are                                scope of oil, gas, and
 obtained by a third                            sulphur prospecting on
 party, what must we                            the OCS under BOEM.
 both do?
Sec.   280.60 Which of  Moved to BOEM, Sec.    This section addresses
 my costs will be        580.60.                activities within the
 reimbursed?                                    scope of oil, gas, and
                                                sulphur prospecting on
                                                the OCS under BOEM.
Sec.   280.61 Which of  Moved to BOEM, Sec.    This section addresses
 my costs will not be    580.61.                activities within the
 reimbursed?                                    scope of oil, gas, and
                                                sulphur prospecting on
                                                the OCS under BOEM.
Sec.   280.70 What      Moved to BOEM, Sec.    This section addresses
 data and information    580.70.                activities within the
 will be protected                              scope of oil, gas, and
 from public                                    sulphur prospecting on
 disclosure?                                    the OCS under BOEM.
Sec.   280.71 What is   Moved to BOEM, Sec.    This section addresses
 the timetable for       580.71.                activities within the
 release of data and                            scope of oil, gas, and
 information?                                   sulphur prospecting on
                                                the OCS under BOEM.
Sec.   280.72 What      Moved to BOEM, Sec.    This section addresses
 procedure will MMS      580.72.                activities within the
 follow to disclose                             scope of oil, gas, and
 acquired data and                              sulphur prospecting on
 information to a                               the OCS under BOEM.
 contractor for
 reproduction,
 processing, and
 interpretation?
Sec.   280.73 Will MMS  Moved to BOEM, Sec.    This section addresses
 share data and          580.73.                activities within the
 information with                               scope of oil, gas, and
 coastal States?                                sulphur prospecting on
                                                the OCS under BOEM.
------------------------------------------------------------------------
                    Subpart E--Information Collection
------------------------------------------------------------------------
Sec.   280.80           Moved to BOEM, Sec.    This section addresses
 Paperwork Reduction     580.80.                activities within the
 Act statement--                                scope of oil, gas and
 information                                    sulphur prospecting on
 collection                                     the OCS under BOEM.
------------------------------------------------------------------------

Part 281--Leasing of Minerals Other Than Oil, Gas, and Sulphur in the 
Outer Continental Shelf--Moved to BOEM in Its Entirety, Chapter V, Part 
581

    The Office of Natural Resources Revenue (ONRR) is the office that 
has the authority to determine the value for royalty purposes of 
minerals and other products produced on the OCS under Secretarial Order 
No. 3299. Because ONRR is responsible for valuation, technical 
corrections were made to this part to reflect that authority. This rule 
does not change the valuation authority possessed by ONRR or the 
procedures by which that authority is implemented. It merely revises 
the references in the regulations to conform to those in current 
Secretarial delegations. It has no effect on the rights, obligations, 
or interests of affected parties. It affects solely the organization, 
procedure, and practice of the agencies.

                  Table L--Detailed Table for Part 281
------------------------------------------------------------------------
                                   Implementing
   Current citation and BSEE     bureau and BOEM
   citation (if applicable)        citation (if         Explanation
                                   applicable)
------------------------------------------------------------------------
                           Subpart A--General
------------------------------------------------------------------------
Sec.   281.0 Authority for      Moved to BOEM,     This section
 information collection.         Sec.   581.0.      addresses activities
                                                    within the scope of
                                                    leasing of minerals
                                                    other than oil, gas,
                                                    and sulphur on the
                                                    OCS under BOEM.
Sec.   281.1 Purpose and        Moved to BOEM,     This section
 applicability.                  Sec.   581.1.      addresses activities
                                                    within the scope of
                                                    leasing of minerals
                                                    other than oil, gas,
                                                    and sulphur on the
                                                    OCS under BOEM.
Sec.   281.2 Authority........  Moved to BOEM,     This section
                                 Sec.   581.2.      addresses activities
                                                    within the scope of
                                                    leasing of minerals
                                                    other than oil, gas,
                                                    and sulphur on the
                                                    OCS under BOEM.
Sec.   281.3 Definitions......  Moved to BOEM,     This section
                                 Sec.   581.3.      addresses activities
                                                    within the scope of
                                                    leasing of minerals
                                                    other than oil, gas,
                                                    and sulphur on the
                                                    OCS under BOEM.
Sec.   281.4 Qualifications of  Moved to BOEM,     This section
 lessees.                        Sec.   581.4.      addresses activities
                                                    within the scope of
                                                    leasing of minerals
                                                    other than oil, gas,
                                                    and sulphur on the
                                                    OCS under BOEM.
Sec.   281.5 False statements.  Moved to BOEM,     This section
                                 Sec.   581.5.      addresses activities
                                                    within the scope of
                                                    leasing of minerals
                                                    other than oil, gas,
                                                    and sulphur on the
                                                    OCS under BOEM.
Sec.   281.6 Appeals..........  Moved to BOEM,     This section
                                 Sec.   581.6.      addresses activities
                                                    within the scope of
                                                    leasing of minerals
                                                    other than oil, gas,
                                                    and sulphur on the
                                                    OCS under BOEM.
Sec.   281.7 Disclosure of      Moved to BOEM,     This section
 information to the public.      Sec.   581.7.      addresses activities
                                                    within the scope of
                                                    leasing of minerals
                                                    other than oil, gas,
                                                    and sulphur on the
                                                    OCS under BOEM.

[[Page 64457]]

 
Sec.   281.8 Rights to          Moved to BOEM,     This section
 minerals.                       Sec.   581.8.      addresses activities
                                                    within the scope of
                                                    leasing of minerals
                                                    other than oil, gas,
                                                    and sulphur on the
                                                    OCS under BOEM.
Sec.   281.9 Jurisdictional     Moved to BOEM,     This section
 controversies.                  Sec.   581.9.      addresses activities
                                                    within the scope of
                                                    leasing of minerals
                                                    other than oil, gas,
                                                    and sulphur on the
                                                    OCS under BOEM.
------------------------------------------------------------------------
                      Subpart B--Leasing Procedures
------------------------------------------------------------------------
Sec.   281.11 Unsolicited       Moved to BOEM,     This section
 request for a lease sale.       Sec.   581.11.     addresses activities
                                                    within the scope of
                                                    leasing of minerals
                                                    other than oil, gas,
                                                    and sulphur on the
                                                    OCS under BOEM.
Sec.   281.12 Request for OCS   Moved to BOEM,     This section
 mineral information and         Sec.   581.12.     addresses activities
 interest.                                          within the scope of
                                                    leasing of minerals
                                                    other than oil, gas,
                                                    and sulphur on the
                                                    OCS under BOEM.
Sec.   281.13 Joint State/      Moved to BOEM,     This section
 Federal coordination.           Sec.   581.13.     addresses activities
                                                    within the scope of
                                                    leasing of minerals
                                                    other than oil, gas,
                                                    and sulphur on the
                                                    OCS under BOEM.
Sec.   281.14 OCS mining area   Moved to BOEM,     This section
 identification.                 Sec.   581.14.     addresses activities
                                                    within the scope of
                                                    leasing of minerals
                                                    other than oil, gas,
                                                    and sulphur on the
                                                    OCS under BOEM.
Sec.   281.15 Tract size......  Moved to BOEM,     This section
                                 Sec.   581.15.     addresses activities
                                                    within the scope of
                                                    leasing of minerals
                                                    other than oil, gas,
                                                    and sulphur on the
                                                    OCS under BOEM.
Sec.   281.16 Proposed leasing  Moved to BOEM,     This section
 notice.                         Sec.   581.16.     addresses activities
                                                    within the scope of
                                                    leasing of minerals
                                                    other than oil, gas,
                                                    and sulphur on the
                                                    OCS under BOEM.
Sec.   281.17 Leasing notice..  Moved to BOEM,     This section
                                 Sec.   581.17.     addresses activities
                                                    within the scope of
                                                    leasing of minerals
                                                    other than oil, gas,
                                                    and sulphur on the
                                                    OCS under BOEM.
Sec.   281.18 Bidding system..  Moved to BOEM,     This section
                                 Sec.   581.18.     addresses activities
                                                    within the scope of
                                                    leasing of minerals
                                                    other than oil, gas,
                                                    and sulphur on the
                                                    OCS under BOEM.
Sec.   281.19 Lease term......  Moved to BOEM,     This section
                                 Sec.   581.19.     addresses activities
                                                    within the scope of
                                                    leasing of minerals
                                                    other than oil, gas,
                                                    and sulphur on the
                                                    OCS under BOEM.
Sec.   281.20 Submission of     Moved to BOEM,     This section
 bids.                           Sec.   581.20.     addresses activities
                                                    within the scope of
                                                    leasing of minerals
                                                    other than oil, gas,
                                                    and sulphur on the
                                                    OCS under BOEM.
Sec.   281.21 Award of leases.  Moved to BOEM,     This section
                                 Sec.   581.21.     addresses activities
                                                    within the scope of
                                                    leasing of minerals
                                                    other than oil, gas,
                                                    and sulphur on the
                                                    OCS under BOEM.
Sec.   281.22 Lease form......  Moved to BOEM,     This section
                                 Sec.   581.22.     addresses activities
                                                    within the scope of
                                                    leasing of minerals
                                                    other than oil, gas,
                                                    and sulphur on the
                                                    OCS under BOEM.
Sec.   281.23 Effective date    Moved to BOEM,     This section
 of leases.                      Sec.   581.23.     addresses activities
                                                    within the scope of
                                                    leasing of minerals
                                                    other than oil, gas,
                                                    and sulphur on the
                                                    OCS under BOEM.
------------------------------------------------------------------------
                   Subpart C--Financial Considerations
------------------------------------------------------------------------
Sec.   281.26 Payments........  Moved to BOEM,     This section
                                 Sec.   581.26.     addresses activities
                                                    within the scope of
                                                    leasing of minerals
                                                    other than oil, gas,
                                                    and sulphur on the
                                                    OCS under BOEM.
Sec.   281.27 Annual rental...  Moved to BOEM,     This section
                                 Sec.   581.27.     addresses activities
                                                    within the scope of
                                                    leasing of minerals
                                                    other than oil, gas,
                                                    and sulphur on the
                                                    OCS under BOEM.
Sec.   281.28 Royalty.........  Moved to BOEM,     This section
                                 Sec.   581.28.     addresses activities
                                                    within the scope of
                                                    leasing of minerals
                                                    other than oil, gas,
                                                    and sulphur on the
                                                    OCS under BOEM.
Sec.   281.29 Royalty           Moved to BOEM,     This section
 valuation.                      Sec.   581 29.     addresses activities
                                                    within the scope of
                                                    leasing of minerals
                                                    other than oil, gas,
                                                    and sulphur on the
                                                    OCS under BOEM.
Sec.   281.30 Minimum royalty.  Moved to BOEM,     This section
                                 Sec.   581.30.     addresses activities
                                                    within the scope of
                                                    leasing of minerals
                                                    other than oil, gas,
                                                    and sulphur on the
                                                    OCS under BOEM.
Sec.   281.31 Overriding        Moved to BOEM,     This section
 royalties.                      Sec.   581.31.     addresses activities
                                                    within the scope of
                                                    leasing of minerals
                                                    other than oil, gas,
                                                    and sulphur on the
                                                    OCS under BOEM.
Sec.   281.32 Waiver,           Moved to BOEM,     This section
 suspension, or reduction of     Sec.   581.32.     addresses activities
 rental, minimum royalty or                         within the scope of
 production royalty.                                leasing of minerals
                                                    other than oil, gas,
                                                    and sulphur on the
                                                    OCS under BOEM.
Sec.   281.33 Bonds and         Moved to BOEM,     This section
 bonding requirements.           Sec.   581.33.     addresses activities
                                                    within the scope of
                                                    leasing of minerals
                                                    other than oil, gas,
                                                    and sulphur on the
                                                    OCS under BOEM.
------------------------------------------------------------------------
               Subpart D--Assignments and Lease Extensions
------------------------------------------------------------------------
Sec.   281.40 Assignment of     Moved to BOEM,     This section
 leases or interests therein.    Sec.   581.40.     addresses activities
                                                    within the scope of
                                                    leasing of minerals
                                                    other than oil, gas,
                                                    and sulphur on the
                                                    OCS under BOEM.
Sec.   281.41 Requirements for  Moved to BOEM,     This section
 filing for transfers.           Sec.   581.41.     addresses activities
                                                    within the scope of
                                                    leasing of minerals
                                                    other than oil, gas,
                                                    and sulphur on the
                                                    OCS under BOEM.
Sec.   281.42 Effect of         Moved to BOEM,     This section
 assignment on particular        Sec.   581.42.     addresses activities
 lease.                                             within the scope of
                                                    leasing of minerals
                                                    other than oil, gas,
                                                    and sulphur on the
                                                    OCS under BOEM.
Sec.   281.43 Effect of         Moved to BOEM,     This section
 suspensions on lease term.      Sec.   581.43.     addresses activities
                                                    within the scope of
                                                    leasing of minerals
                                                    other than oil, gas,
                                                    and sulphur on the
                                                    OCS under BOEM.
------------------------------------------------------------------------
                    Subpart E--Termination of Leases
------------------------------------------------------------------------
Sec.   281.46 Relinquishment    Moved to BOEM,     This section
 of leases or parts of leases.   Sec.   581.46.     addresses activities
                                                    within the scope of
                                                    leasing of minerals
                                                    other than oil, gas,
                                                    and sulphur on the
                                                    OCS under BOEM.
Sec.   281.47 Cancellation of   Moved to BOEM,     This section
 leases.                         Sec.   581.47.     addresses activities
                                                    within the scope of
                                                    leasing of minerals
                                                    other than oil, gas,
                                                    and sulphur on the
                                                    OCS under BOEM.
------------------------------------------------------------------------


[[Page 64458]]

Part 282--Operations in the Outer Continental Shelf for Minerals Other 
Than Oil, Gas, and Sulphur

    Both BOEM and BSEE have responsibilities for operations conducted 
under a mineral lease for OCS minerals other than oil, gas, or sulphur.
    As stated previously, ONRR has the authority to determine the value 
for royalty purposes of minerals and other products produced on the OCS 
under Secretarial Order No. 3299. Because ONRR is the office 
responsible for valuation, technical corrections were made to this part 
to reflect that authority. This rule does not change the valuation 
authority possessed by ONRR or the procedures by which that authority 
is implemented. It merely revises the references in the regulations to 
conform to those in current Secretarial delegations. It has no effect 
on the rights, obligations, or interests of affected parties. It 
affects solely the organization, procedure, and practice of the 
agencies.
    These responsibilities were divided between the bureaus as follows:

                  Table M--Detailed Table for Part 282
------------------------------------------------------------------------
                                   Implementing
   Current citation and BSEE     bureau and BOEM
   citation (if applicable)        citation (if         Explanation
                                   applicable)
------------------------------------------------------------------------
                           Subpart A--General
------------------------------------------------------------------------
Sec.   282.0 Authority for      Both BSEE and      Both agencies need
 information collection.         BOEM Sec.          the authority for
                                 582.0.             information
                                                    collection.
Sec.   282.1 Purpose and        Both BSEE and      Needed by both
 authority.                      BOEM Sec.          agencies.
                                 582.1.
Sec.   282.2 Scope............  Both BSEE and      Needed by both
                                 BOEM Sec.          agencies.
                                 582.2.
Sec.   282.3 Definitions......  Both BSEE and      Needed by both
                                 BOEM Sec.          agencies.
                                 582.3.
Sec.   282.4 Opportunities for  Moved to BOEM,     BOEM responsibility.
 review and comment.             Sec.   582.4.
Sec.   282.5 Disclosure of      Both BSEE and      Needed by both
 data and information to the     BOEM Sec.          agencies.
 public.                         582.5.
Sec.   282.6 Disclosure of      Both BSEE and      Needed by both
 data and information to an      BOEM Sec.          agencies.
 adjacent State.                 582.6.
Sec.   282.7 Jurisdictional     Both BSEE and      Needed by both
 controversies.                  BOEM Sec.          agencies.
                                 582.7.
------------------------------------------------------------------------
        Subpart B--Jurisdiction and Responsibilities of Director
------------------------------------------------------------------------
Sec.   282.10 Jurisdiction and  Both BSEE and      Needed by both
 responsibilities of Director.   BOEM Sec.          agencies.
                                 582.10.
Sec.   282.11 Director's        Moved to BOEM,     Paragraph (d)
 authority.                      Sec.   582.11.     involves units,
                                 Paragraph (d) on   which is a BSEE
                                 mining units is    function. Paragraph
                                 in both.           (d) also contains
                                                    BOEM
                                                    responsibilities as
                                                    it mentions plans.
Sec.   282.12 Director's        Responsibilities   Paragraphs (a), (e),
 responsibilities.               are shared by      (f), and (h) are
                                 both BSEE and      retained in BSEE.
                                 BOEM.              Paragraphs (a), (b),
                                                    (c), (d) and (g) are
                                                    in BOEM. This
                                                    section contains,
                                                    but is not limited
                                                    to, general
                                                    statements on the
                                                    Director's
                                                    responsibilities;
                                                    language on mining
                                                    plan approvals,
                                                    delineation testing
                                                    and lease
                                                    operations; and
                                                    conditions under
                                                    which the Director
                                                    may prescribe or
                                                    approve departures.
Sec.   282.13 Suspension of     Retained in BSEE.  Suspensions are under
 production or other                                the authority of
 operations.                                        BSEE.
Sec.   282.14 Noncompliance,    Both BSEE and      BSEE is responsible
 remedies, and penalties.        BOEM Sec.          for addressing
                                 582.14.            noncompliance,
                                                    remedies, and
                                                    penalties. Needed in
                                                    both agencies.
Sec.   282.15 Cancellation of   Moved to BOEM,     BOEM is responsible
 leases.                         Sec.   582.15.     for lease
                                                    administration.
------------------------------------------------------------------------
         Subpart C--Obligations and Responsibilities of Lessees
------------------------------------------------------------------------
Sec.   282.20 Obligations and   Moved to BOEM,     This section
 responsibilities of lessees.    Sec.   582.20.     addresses
                                                    obligations and
                                                    responsibilities of
                                                    lessees that are the
                                                    responsibility of
                                                    BOEM.
Sec.   282.21 Plans, general..  Moved to BOEM,     This section
                                 Sec.   582.21,     addresses plans that
                                 except paragraph   are the
                                 (e), which is in   responsibility of
                                 both.              BOEM. Paragraph (e)
                                                    addresses leasehold
                                                    activities and how
                                                    those activities
                                                    must be carried out.
                                                    Leasehold activities
                                                    are generally
                                                    operational in
                                                    nature (i.e.,
                                                    drilling,
                                                    production) and
                                                    therefore these
                                                    responsibilities are
                                                    also vested in BSEE.
Sec.   282.22 Delineation Plan  Moved to BOEM,     This section
                                 Sec.   582.22.     addresses plans that
                                                    are the
                                                    responsibility of
                                                    BOEM.
Sec.   282.23 Testing Plan....  Moved to BOEM,     This section
                                 Sec.   582.23.     addresses plans that
                                                    are the
                                                    responsibility of
                                                    BOEM.
Sec.   282.24 Mining Plan.....  Moved to BOEM,     This section
                                 Sec.   582.24.     addresses plans that
                                                    are the
                                                    responsibility of
                                                    BOEM.
Sec.   282.25 Plan              Moved to BOEM,     This section
 modification.                   Sec.   582.25.     addresses plans that
                                                    are the
                                                    responsibility of
                                                    BOEM.
Sec.   282.26 Contingency Plan  Moved to BOEM,     This section
                                 Sec.   582.26.     addresses plans that
                                                    are the
                                                    responsibility of
                                                    BOEM.
Sec.   282.27 Conduct of        Retained in BSEE.  Paragraph (i)
 operations.                     Paragraph (i)      addresses plans that
                                 also in BOEM,      are the
                                 Sec.   582.27.     responsibility of
                                                    BOEM.
Sec.   282.28 Environmental     Moved to BOEM      Paragraphs (c)(1),
 protection measures.            Sec.   582.28.     (c)(3) and (c)(4)
                                 Paragraphs         pertain to
                                 (c)(1), (c)(2),    mitigation,
                                 (c)(3), (c)(4)     observations, and
                                 and (c)(6), and    testing activities.
                                 (d) are retained   Paragraph (d)
                                 in BSEE.           describes ways to
                                 Paragraphs         minimize
                                 (c)(2) and         environmental
                                 (c)(6) are in      impacts. Overseeing
                                 both.              these activities is
                                                    a BSEE
                                                    responsibility. Both
                                                    BOEM and BSEE have
                                                    discrete monitoring
                                                    functions under
                                                    (c)(2) and (c)(6).
Sec.   282.29 Reports and       Moved to BOEM,     A resource evaluation
 records.                        Sec.   582.29.     function under BOEM.
Sec.   282.30 Right of use and  Moved to BOEM,     BOEM has the
 easement.                       Sec.   582.30.     authority to grant
                                                    rights of use and
                                                    easement.

[[Page 64459]]

 
Sec.   282.31 Suspension of     Retained in BSEE.  BSEE has the
 production or other                                authority to suspend
 operations.                                        production or other
                                                    operations.
------------------------------------------------------------------------
                           Subpart D--Payments
------------------------------------------------------------------------
Sec.   282.40 Bonds...........  Moved to BOEM,     Financial assurance
                                 Sec.   582.40.     is a BOEM function
                                                    with a cross
                                                    reference provided
                                                    for BSEE.
Sec.   282.41 Method of         Both BSEE and      ONRR regulations at
 royalty calculation.            BOEM, Sec.         30 CFR part 1206 may
                                 582.41.            apply. Otherwise,
                                                    lessees must comply
                                                    with BOEM's
                                                    procedures specified
                                                    in lease notices.
Sec.   282.42 Payments........  Moved to BOEM,     BOEM.
                                 Sec.   582.42.
------------------------------------------------------------------------
                           Subpart E--Appeals
------------------------------------------------------------------------
Sec.   282.50 Appeals.........  Both BSEE and      Both agencies need
                                 BOEM, Sec.         the procedures for
                                 582.50.            addressing appeals.
------------------------------------------------------------------------

Part 285--Renewable Energy Alternate Uses of Existing Facilities on the 
Outer Continental Shelf--Moved in Its Entirety to BOEM, Chapter V, Part 
585

    BOEM will manage the Renewable Energy Program for the near future. 
Once this program is more established and larger scale operations 
begin, it will be reorganized and a determination will be made 
regarding what functions will be distributed between the two bureaus; 
BSEE and BOEM.

Subchapter C--Appeals

Part 290--Appeals Procedures--Both BSEE and BOEM Will Have This Part in 
Its Entirety

                  Table N--Detailed Table for Part 290
------------------------------------------------------------------------
 Current citation and    Implementing bureau
   BSEE citation (if    and BOEM citation (if         Explanation
      applicable)            applicable)
------------------------------------------------------------------------
        Subpart A--Offshore Minerals Management Appeal Procedures
------------------------------------------------------------------------
Sec.   290.1 What is    Both BSEE and BOEM     Both BSEE and BOEM need
 the purpose of this     Sec.   590.1.          to provide opportunity
 subpart?                                       for appeals of
                                                decisions.
Sec.   290.2 Who may    Both BSEE and BOEM     Both BSEE and BOEM need
 appeal?                 Sec.   590.2.          to provide opportunity
                                                for appeals of
                                                decisions.
Sec.   290.3 What is    Both BSEE and BOEM     Both BSEE and BOEM. need
 the time limit for      Sec.   590.3.          to provide opportunity
 filing an appeal?                              for appeals of
                                                decisions.
Sec.   290.4 How do I   Both BSEE and BOEM     Both BSEE and BOEM need
 file an appeal?         Sec.   590.4.          to provide opportunity
                                                for appeals of
                                                decisions.
Sec.   290.5 Can I      Both BSEE and BOEM     Both BSEE and BOEM need
 obtain an extension     Sec.   590.5.          to provide opportunity
 for filing my Notice                           for appeals of
 of Appeal?                                     decisions.
Sec.   290.6 Are        Both BSEE and BOEM     Both BSEE and BOEM need
 informal resolutions    Sec.   590.6.          to provide opportunity
 permitted?                                     for appeals of
                                                decisions.
Sec.   290.7 Do I have  Both BSEE and BOEM     Both BSEE and BOEM need
 to comply with the      Sec.   590.7.          to provide opportunity
 decision or order                              for appeals of
 while my appeal is                             decisions.
 pending?
Sec.   290.8 How do I   Both BSEE and BOEM     Both BSEE and BOEM need
 exhaust my              Sec.   590.8.          to provide opportunity
 administrative                                 for appeals of
 remedies?                                      decisions.
------------------------------------------------------------------------
                          Subpart B--[Reserved]
------------------------------------------------------------------------

Part 291--Open and Nondiscriminatory Access to Oil and Gas Pipelines 
Under the Outer Continental Shelf Lands Act--Retained by BSEE in Its 
Entirety

                  Table O--Detailed Table for Part 291
------------------------------------------------------------------------
                                   Implementing
   Current citation and BSEE     bureau and BOEM
   citation (if applicable)        citation (if        Justification
                                   applicable)
------------------------------------------------------------------------
                          SUBCHAPTER C--APPEALS
------------------------------------------------------------------------
Sec.   291.1 What is MMS's      Retained in its    This section
 authority to collect            entirety in        addresses
 information?                    BSEE, chapter II.  information
                                                    collection authority
                                                    for open and
                                                    nondiscriminatory
                                                    access to oil and
                                                    gas pipelines under
                                                    OCSLA. Offshore
                                                    operations are under
                                                    the authority of
                                                    BSEE.

[[Page 64460]]

 
Sec.   291.100 What is the      Retained in its    This section
 purpose of this part?           entirety in        addresses purpose of
                                 BSEE, chapter II.  open and
                                                    nondiscriminatory
                                                    access to oil and
                                                    gas pipelines under
                                                    OCSLA. Offshore
                                                    operations are under
                                                    the authority of
                                                    BSEE.
Sec.   291.101 What             Retained in its    This section
 definitions apply to this       entirety in        addresses the
 part?                           BSEE, chapter II.  definitions that
                                                    pertain to open and
                                                    nondiscriminatory
                                                    access to oil and
                                                    gas pipelines under
                                                    OCSLA. Offshore
                                                    operations are under
                                                    the authority of
                                                    BSEE.
Sec.   291.102 May I call the   Retained in its    This section
 MMS Hotline to informally       entirety in        addresses open and
 resolve an allegation that      BSEE, chapter II.  nondiscriminatory
 open and nondiscriminatory                         access to oil and
 access was denied?                                 gas pipelines under
                                                    OCSLA. Offshore
                                                    operations are under
                                                    the authority of
                                                    BSEE.
Sec.   291.103 May I use        Retained in its    This section
 alternative dispute             entirety in        addresses open and
 resolution to informally        BSEE, chapter II.  nondiscriminatory
 resolve an allegation that                         access to oil and
 open and nondiscriminatory                         gas pipelines under
 access was denied?                                 OCSLA. Offshore
                                                    operations are under
                                                    the authority of
                                                    BSEE.
Sec.   291.104 Who may file a   Retained in its    This section
 complaint or a third-party      entirety in        addresses open and
 brief?                          BSEE, chapter II.  nondiscriminatory
                                                    access to oil and
                                                    gas pipelines under
                                                    OCSLA. Offshore
                                                    operations are under
                                                    the authority of
                                                    BSEE.
Sec.   291.105 What must a      Retained in its    This section
 complaint contain?              entirety in        addresses open and
                                 BSEE, chapter II.  nondiscriminatory
                                                    access to oil and
                                                    gas pipelines under
                                                    OCSLA. Offshore
                                                    operations are under
                                                    the authority of
                                                    BSEE.
Sec.   291.106 How do I file a  Retained in its    This section
 complaint?                      entirety in        addresses open and
                                 BSEE, chapter II.  nondiscriminatory
                                                    access to oil and
                                                    gas pipelines under
                                                    OCSLA. Offshore
                                                    operations are under
                                                    the authority of
                                                    BSEE.
Sec.   291.107 How do I answer  Retained in its    This section
 a complaint?                    entirety in        addresses open and
                                 BSEE, chapter II.  nondiscriminatory
                                                    access to oil and
                                                    gas pipelines under
                                                    OCSLA. Offshore
                                                    operations are under
                                                    the authority of
                                                    BSEE.
Sec.   291.108 How do I pay     Retained in its    This section
 the processing fee?             entirety in        addresses open and
                                 BSEE, chapter II.  nondiscriminatory
                                                    access to oil and
                                                    gas pipelines under
                                                    OCSLA. Offshore
                                                    operations are under
                                                    the authority of
                                                    BSEE.
Sec.   291.109 Can I ask for a  Retained in its    This section
 fee waiver or a reduced         entirety in        addresses open and
 processing fee?                 BSEE, chapter II.  nondiscriminatory
                                                    access to oil and
                                                    gas pipelines under
                                                    OCSLA. Offshore
                                                    operations are under
                                                    the authority of
                                                    BSEE.
Sec.   291.110 Who may MMS      Retained in its    This section
 require to produce              entirety in        addresses open and
 information?                    BSEE, chapter II.  nondiscriminatory
                                                    access to oil and
                                                    gas pipelines under
                                                    OCSLA. Offshore
                                                    operations are under
                                                    the authority of
                                                    BSEE.
Sec.   291.111 How does MMS     Retained in its    This section
 treat the confidential          entirety in        addresses open and
 information I provide?          BSEE, chapter II.  nondiscriminatory
                                                    access to oil and
                                                    gas pipelines under
                                                    OCSLA. Offshore
                                                    operations are under
                                                    the authority of
                                                    BSEE.
Sec.   291.112 What process     Retained in its    This section
 will MMS follow in rendering    entirety in        addresses open and
 a decision on whether a         BSEE, chapter II.  nondiscriminatory
 grantee or transporter has                         access to oil and
 provided open and                                  gas pipelines under
 nondiscriminatory access?                          OCSLA. Offshore
                                                    operations are under
                                                    the authority of
                                                    BSEE.
Sec.   291.113 What actions     Retained in its    This section
 may MMS take to remedy denial   entirety in        addresses open and
 of open and nondiscriminatory   BSEE, chapter II.  nondiscriminatory
 access?                                            access to oil and
                                                    gas pipelines under
                                                    OCSLA. Offshore
                                                    operations are under
                                                    the authority of
                                                    BSEE.
Sec.   291.114 How do I appeal  Retained in its    This section
 to the IBLA?                    entirety in        addresses open and
                                 BSEE, chapter II.  nondiscriminatory
                                                    access to oil and
                                                    gas pipelines under
                                                    OCSLA. Offshore
                                                    operations are under
                                                    the authority of
                                                    BSEE.
Sec.   291.115 How do I         Retained in its    This section
 exhaust administrative          entirety in        addresses open and
 remedies?                       BSEE, chapter II.  nondiscriminatory
                                                    access to oil and
                                                    gas pipelines under
                                                    OCSLA. Offshore
                                                    operations are under
                                                    the authority of
                                                    BSEE.
------------------------------------------------------------------------

Procedural Matters

Regulatory Planning and Review (Executive Order (E.O.) 12866)

    This direct final rule is not a significant rule as determined by 
the Office of Management and Budget (OMB) and is not subject to review 
under E.O. 12866. This direct final rule reorganizes the title 30 CFR 
chapter II regulations; this rule does not change existing regulatory 
requirements.
    (1) This direct final rule will not have an annual effect of $100 
million or more on the economy. It will not adversely affect in a 
material way the economy, productivity, competition: jobs; the 
environment; public health or safety; or state, local, or Tribal 
governments or communities.
    (2) This direct final rule will not create a serious inconsistency 
or otherwise interfere with an action taken or planned by another 
agency.
    (3) This direct final rule will not alter the budgetary effects of 
entitlements, grants, user fees, or loan programs or the rights or 
obligations of their recipients.
    (4) This direct final rule will not raise novel legal or policy 
issues arising out of legal mandates, the President's priorities, or 
the principles set forth in E.O. 12866.

Regulatory Flexibility Act

    This direct final rule is exempt from the notice and comment 
provisions of

[[Page 64461]]

the Administrative Procedure Act (APA), 5 U.S.C. 553; therefore, the 
requirements of the Regulatory Flexibility Act do not apply, 5 U.S.C. 
603(a).

Small Business Regulatory Enforcement Fairness Act

    This direct final rule is not a major rule under the Small Business 
Regulatory Enforcement Fairness Act (5 U.S.C. 801 et seq.). This direct 
final rule:
    a. Will not have an annual effect on the economy of $100 million or 
more.
    b. Will not cause a major increase in costs or prices for 
consumers; individual industries; Federal, state, or local government 
agencies; or geographic regions.
    c. Will not have significant adverse effects on competition, 
employment, investment, productivity, innovation, or the ability of 
U.S.-based enterprises to compete with foreign-based enterprises.
    The requirements apply to all entities operating on the OCS. This 
direct final rule reorganizes the title 30 CFR chapter II regulations 
and does not change existing regulatory requirements.

Unfunded Mandates Reform Act of 1995

    This direct final rule will not impose an unfunded mandate on 
state, local, or Tribal governments, or the private sector of more than 
$100 million per year. This direct final rule will not have a 
significant or unique effect on state, local, or Tribal governments, or 
the private sector. A statement containing the information required by 
the Unfunded Mandates Reform Act (2 U.S.C. 1501 et seq.) is not 
required.

Takings Implication Assessment (E.O. 12630)

    Under the criteria in E.O. 12630, this direct final rule does not 
have significant takings implications. This direct final rule is not a 
governmental action capable of interference with constitutionally 
protected property rights. A Takings Implication Assessment is not 
required.

Federalism (E.O. 13132)

    Under the criteria in E.O. 13132, this direct final rule does not 
have federalism implications. This direct final rule will not 
substantially and directly affect the relationship between the Federal 
and State governments. To the extent that State and local governments 
have a role in OCS activities, this direct final rule will not affect 
that role. A Federalism Assessment is not required.

Civil Justice Reform (E.O. 12988)

    This direct final rule complies with the requirements of E.O. 
12988. Specifically, this rule:
    (a) Meets the criteria of section 3(a) requiring that all 
regulations be reviewed to eliminate errors and ambiguity and be 
written to minimize litigation; and
    (b) Meets the criteria of section 3(b)(2) requiring that all 
regulations be written in clear language and contain clear legal 
standards.

Consultation With Indian Tribes (E.O. 13175)

    Under the criteria in E.O. 13175, we have evaluated this direct 
final rule and determined that it has no substantial effects on 
federally recognized Indian Tribes.

Paperwork Reduction Act (PRA) of 1995

    This final rule does not contain new information collection 
requirements, and a submission to OMB is not required under 44 U.S.C. 
3501 et seq. All information collections referred to in this rulemaking 
are in the 1010 numbering series and are unchanged.

National Environmental Policy Act of 1969

    This rule does not constitute a major Federal action significantly 
affecting the quality of the human environment. We evaluated this rule 
under the criteria of the National Environmental Policy Act, 43 CFR 
Part 46 and 516 Departmental Manual 15. This rule meets the criteria 
set forth in 43 CFR 46.210(i) in that this proposed rule is ``* * * of 
an administrative, financial, legal, technical, or procedural nature * 
* *.'' This rule also meets the criteria set forth in 516 Departmental 
Manual 15.4(C)(1) for a ``Categorical Exclusion'' in that its impacts 
are limited to administrative, economic or technological effects. 
Further, we have evaluated this proposed rule to determine if it 
involves any of the extraordinary circumstances that would require an 
environmental assessment or an environmental impact statement as set 
forth in 43 CFR 46.215. We concluded that this rule does not meet any 
of the criteria for extraordinary circumstances as set forth therein.

Data Quality Act

    In developing this rule, we did not conduct or use a study, 
experiment, or survey requiring peer review under the Data Quality Act 
(Pub. L. 106-554, app. C section 515, 114 Stat. 2763, 2763A-153-154).

Effects of the Nation's Energy Supply (E.O. 13211)

    This direct final rule is not a significant energy action under the 
definition in E.O. 13211. A Statement of Energy Effects is not 
required.

List of Subjects

30 CFR Part 203

    Continental shelf, Government contracts, Indians--lands, Mineral 
royalties, Oil and gas exploration, Public lands--mineral resources, 
Sulphur.

30 CFR Part 250

    Administrative practice and procedure, Continental shelf, Oil and 
gas exploration, Public lands--mineral resources, Reporting and 
recordkeeping requirements.

30 CFR Part 251

    Continental shelf, Freedom of information, Oil and gas exploration, 
Public lands--mineral resources, Reporting and recordkeeping 
requirements, Research.

30 CFR Part 252

    Continental shelf, Freedom of information, Intergovernmental 
relations, Oil and gas exploration, Public lands--mineral resources, 
Reporting and recordkeeping requirements.

30 CFR Part 254

    Continental shelf, Intergovernmental relations, Oil and gas 
exploration, Oil pollution, Pipelines, Public lands--mineral resources, 
Reporting and recordkeeping requirements.

30 CFR Part 256

    Administrative practice and procedure, Continental shelf, 
Environmental protection, Government contracts, Intergovernmental 
relations, Oil and gas exploration, Public lands--mineral resources, 
Public lands--rights-of-way, Reporting and recordkeeping requirements, 
Surety bonds.

30 CFR Part 270

    Administrative practice and procedure, Civil rights, Continental 
shelf, Government contracts, Oil and gas exploration, Public lands--
mineral resources.

30 CFR Part 282

    Administrative practice and procedure, Continental shelf, 
Environmental protection, Government contracts, Intergovernmental 
relations, Mineral royalties, Penalties, Public lands--mineral 
resources, Reporting

[[Page 64462]]

and recordkeeping requirements, Surety bonds.

30 CFR Part 290

    Administrative practice and procedure.

30 CFR Part 291

    Administrative practice and procedure.

30 CFR Part 519

    Continental shelf, Government contracts, Indians--lands, Mineral 
royalties, Oil and gas exploration, Public lands--mineral resources, 
Sulphur.

30 CFR Part 550

    Administrative practice and procedure, Continental shelf, 
Environmental impact statements, Environmental protection, Government 
contracts, Investigations, Oil and gas exploration, Penalties, 
Pipelines, Public lands--mineral resources, Public lands--rights-of-
way, Reporting and recordkeeping requirements, Sulphur.

30 CFR Part 551

    Continental shelf, Freedom of information, Oil and gas exploration, 
Public lands--mineral resources, Reporting and recordkeeping 
requirements, Research.

30 CFR Part 552

    Continental shelf, Freedom of information, Intergovernmental 
relations, Oil and gas exploration, Public lands--mineral resources, 
Reporting and recordkeeping requirements.

30 CFR Part 553

    Continental shelf, Environmental protection, Intergovernmental 
relations, Oil and gas exploration, Oil pollution, Penalties, 
Pipelines, Public lands--mineral resources, Reporting and recordkeeping 
requirements, Surety bonds.

30 CFR Part 556

    Administrative practice and procedure, Continental shelf, 
Environmental protection, Government contracts, Intergovernmental 
relations, Oil and gas exploration, Public lands--mineral resources, 
Public lands--rights-of-way, Reporting and recordkeeping requirements, 
Surety bonds.

30 CFR Part 559

    Continental shelf, Government contracts, Mineral royalties, Oil and 
gas exploration, Public lands--mineral resources.

30 CFR Part 560

    Continental shelf, Government contracts, Mineral royalties, Oil and 
gas exploration, Public lands--mineral resources, Reporting and 
recordkeeping requirements.

30 CFR Part 570

    Administrative practice and procedure, Civil rights, Continental 
shelf, Government contracts, Oil and gas exploration, Public lands--
mineral resources.

30 CFR Part 580

    Continental shelf, Public lands--mineral resources, Reporting and 
recordkeeping requirements, Research.

30 CFR Part 581

    Administrative practice and procedure, Continental shelf, 
Government contracts, Intergovernmental relations, Mineral royalties, 
Public lands--mineral resources, Reporting and recordkeeping 
requirements, Surety bonds.

30 CFR Part 582

    Administrative practice and procedure, Continental shelf, 
Environmental protection, Government contracts, Intergovernmental 
relations, Mineral royalties, Penalties, Public lands--mineral 
resources, Reporting and recordkeeping requirements, Surety bonds.

30 CFR Part 585

    Continental shelf, Environmental protection, Incorporation by 
reference, Public lands.

30 CFR Part 590

    Administrative practice and procedure.

    Dated: August 18, 2011.
Ned Farquhar,
Deputy Assistant Secretary--Land and Minerals Management.

    For the reasons stated in the preamble, under the authority of 5 
U.S.C. 901 et seq., the Bureau of Safety and Environmental Enforcement 
(BSEE) reassigns chapter II and Bureau of Ocean Energy Management 
(BOEM) establishes chapter V as follows:



TITLE 30--MINERAL RESOURCES

0
1. Chapter II is revised to read as follows:

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

SUBCHAPTER A--MINERALS REVENUE MANAGEMENT

Part
203 RELIEF OR REDUCTION IN ROYALTY RATES
219 RESERVED

SUBCHAPTER B--OFFSHORE

250 OIL AND GAS AND SULPHUR OPERATIONS IN THE OUTER CONTINENTAL 
SHELF
251 GEOLOGICAL AND GEOPHYSICAL (G&G) EXPLORATIONS OF THE OUTER 
CONTINENTAL SHELF
252 OUTER CONTINENTAL SHELF (OCS) OIL AND GAS INFORMATION PROGRAM
253 RESERVED
254 OIL-SPILL RESPONSE REQUIREMENTS FOR FACILITIES LOCATED SEAWARD 
OF THE COAST LINE
256 LEASING OF SULPHUR OR OIL AND GAS IN THE OUTER CONTINENTAL SHELF
259 RESERVED
260 RESERVED
270 NONDISCRIMINATION IN THE OUTER CONTINENTAL SHELF
280 RESERVED
281 RESERVED
282 OPERATIONS IN THE OUTER CONTINENTAL SHELF FOR MINERALS OTHER 
THAN OIL, GAS, AND SULPHUR
285 RESERVED

SUBCHAPTER C--APPEALS

290 APPEAL PROCEDURES
291 OPEN AND NONDISCRIMINATORY ACCESS TO OIL AND GAS PIPELINES UNDER 
THE OUTER CONTINENTAL SHELF LANDS ACT

SUBCHAPTER A--MINERALS REVENUE MANAGEMENT

PART 203--RELIEF OR REDUCTION IN ROYALTY RATES

Subpart A--General Provisions

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

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

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

[[Page 64463]]

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

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

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

Royalty Relief for End-of-Life Leases

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

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

203.60 Who may apply for royalty relief on a case-by-case basis in 
deep water in the Gulf of Mexico or offshore of Alaska?
203.61 How do I assess my chances for getting relief?
203.62 How do I apply for relief?
203.63 Does my application have to include all leases in the field?
203.64 How many applications may I file on a field or a development 
project?
203.65 How long will BSEE take to evaluate my application?
203.66 What happens if BSEE does not act in the time allowed?
203.67 What economic criteria must I meet to get royalty relief on 
an authorized field or project?
203.68 What pre-application costs will BSEE consider in determining 
economic viability?
203.69 If my application is approved, what royalty relief will I 
receive?
203.70 What information must I provide after BSEE approves relief?
203.71 How does BSEE allocate a field's suspension volume between my 
lease and other leases on my field?
203.72 Can my lease receive more than one suspension volume?
203.73 How do suspension volumes apply to natural gas?
203.74 When will BSEE reconsider its determination?
203.75 What risk do I run if I request a redetermination?
203.76 When might BSEE withdraw or reduce the approved size of my 
relief?
203.77 May I voluntarily give up relief if conditions change?
203.78 Do I keep relief approved by BSEE under this part for my 
lease, unit or project if prices rise significantly?
203.79 How do I appeal BSEE's decisions related to royalty relief 
for a deepwater lease or a development or expansion project?
203.80 When can I get royalty relief if I am not eligible for 
royalty relief under other sections in the subpart?

Required Reports

203.81 What supplemental reports do royalty-relief applications 
require?
203.82 What is BSEE's authority to collect this information?
203.83 What is in an administrative information report?
203.84 What is in a net revenue and relief justification report?
203.85 What is in an economic viability and relief justification 
report?
203.86 What is in a G&G report?
203.87 What is in an engineering report?
203.88 What is in a production report?
203.89 What is in a cost report?
203.90 What is in a fabricator's confirmation report?
203.91 What is in a post-production development report?
Subpart C--Federal and Indian Oil [Reserved]
Subpart D--Federal and Indian Gas [Reserved]
Subpart E--Solid Minerals, General [Reserved]
Subpart F [Reserved]
Subpart G--Other Solid Minerals [Reserved]
Subpart H--Geothermal Resources [Reserved]
Subpart I--OCS Sulfur [Reserved]

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

Subpart A--General Provisions


Sec.  203.0  What definitions apply to this part?

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

[[Page 64464]]

reports consisting of the data specified in Sec. Sec.  203.81, 203.83, 
and 203.85 through 203.89, along with one set of digital information, 
which Bureau of Safety and Environmental Enforcement (BSEE) has 
reviewed and found complete.
    Deep well means either an original well or a sidetrack with a 
perforated interval the top of which is at least 15,000 feet TVD SS and 
less than 20,000 feet TVD SS. A deep well subsequently re-perforated at 
less than 15,000 feet TVD SS in the same reservoir is still a deep 
well.
    Determination means the binding decision by BSEE on whether your 
field qualifies for relief or how large a royalty-suspension volume 
must be to make the field economically viable.
    Development project means a project to develop one or more oil or 
gas reservoirs located on one or more contiguous leases that have had 
no production (other than test production) before the current 
application for royalty relief and are either:
    (1) Located in a planning area offshore Alaska; or
    (2) Located in the GOM in a water depth of at least 200 meters and 
wholly west of 87 degrees, 30 minutes West longitude, and were issued 
in a sale held after November 28, 2000.
    Draft application means the preliminary set of information and 
assumptions you submit to seek a nonbinding assessment on whether a 
field could be expected to qualify for royalty relief.
    Eligible lease means a lease that:
    (1) Is issued as part of an OCS lease sale held after November 28, 
1995, and before November 28, 2000;
    (2) Is located in the Gulf of Mexico in water depths of 200 meters 
or deeper;
    (3) Lies wholly west of 87 degrees, 30 minutes West longitude; and
    (4) Is offered subject to a royalty suspension volume.
    Expansion project means a project that meets the following 
requirements:
    (1) You must propose the project in a (BOEM) Development and 
Production Plan, a BOEM Development Operations Coordination Document 
(DOCD), or a BOEM Supplement to a DOCD, approved by the Secretary of 
the Interior after November 28, 1995.
    (2) The project must be located on either:
    (i) A pre-Act lease in the GOM, or a lease in the GOM issued in a 
sale held after November 28, 2000, located wholly west of 87 degrees, 
30 minutes West longitude; or
    (ii) A lease in a planning area offshore Alaska.
    (3) On a pre-Act lease in the GOM, the project:
    (i) Must significantly increase the ultimate recovery of resources 
from one or more reservoirs that have not previously produced 
(extending recovery from reservoirs already in production does not 
constitute a significant increase); and
    (ii) Must involve a substantial capital investment (e.g., fixed-leg 
platform, subsea template and manifold, tension-leg platform, multiple 
well project, etc.).
    (4) For a lease issued in a planning area offshore Alaska, or in 
the GOM after November 28, 2000, the project must involve a new well 
drilled into a reservoir that has not previously produced.
    (5) On a lease in the GOM, the project must not include a reservoir 
the production from which an RSV under Sec. Sec.  203.30 through 203.36 
or Sec. Sec.  203.40 through 203.48 would be applied.
    Fabrication (or start of construction) means evidence of an 
irreversible commitment to a concept and scale of development. Evidence 
includes copies of a binding contract between you (as applicant) and a 
fabrication yard, a letter from a fabricator certifying that continuous 
construction has begun, and a receipt for the customary down payment.
    Field means an area consisting of a single reservoir or multiple 
reservoirs all grouped on, or related to, the same general geological 
structural feature or stratigraphic trapping condition. Two or more 
reservoirs may be in a field, separated vertically by intervening 
impervious strata or laterally by local geologic barriers, or both.
    Lease means a lease or unit.
    New production means any production from a current pre-Act lease 
from which no royalties are due on production, other than test 
production, before November 28, 1995. Also, it means any additional 
production resulting from new lease-development activities on a lease 
issued in a sale after November 28, 2000, or a current pre-Act lease 
under a BOEM DOCD or a BOEM Supplement approved by the Secretary of the 
Interior after November 28, 1995.
    Nonbinding assessment means an opinion by BSEE of whether your 
field could qualify for royalty relief. It is based on your draft 
application and does not entitle the field to relief.
    Non-converted lease means a lease located partly or entirely in 
water less than 200 meters deep issued in a lease sale held after 
January 1, 2001, and before January 1, 2004, whose original lease terms 
provided for an RSV for deep gas production and the lessee has not 
exercised the option under Sec.  203.49 to replace the lease terms for 
royalty relief with those in Sec.  203.0 and Sec. Sec.  203.40 through 
203.48.
    Original well means a well that is drilled without utilizing an 
existing wellbore. An original well includes all sidetracks drilled 
from the original wellbore either before the drilling rig moves off the 
well location or after a temporary rig move that BSEE agrees was forced 
by a weather or safety threat and drilling resumes within 1 year. A 
bypass from an original well (e.g., drilling around material blocking 
the hole or to straighten crooked holes) is part of the original well.
    Participating area means that part of the unit area that BSEE 
determines is reasonably proven by drilling and completion of 
producible wells, geological and geophysical information, and 
engineering data to be capable of producing hydrocarbons in paying 
quantities.
    Performance conditions mean minimum conditions you must meet, after 
we have granted relief and before production begins, to remain 
qualified for that relief. If you do not meet each one of these 
performance conditions, we consider it a change in material fact 
significant enough to invalidate our original evaluation and approval.
    Phase 1 ultra-deep well means an ultra-deep well on a lease that is 
located in water partly or entirely less than 200 meters deep for which 
drilling began before May 18, 2007, and that begins production before 
May 3, 2009, or that meets the requirements to be a certified 
unsuccessful well.
    Phase 2 ultra-deep well means an ultra-deep well for which drilling 
began on or after May 18, 2007; and that either meets the requirements 
to be a certified unsuccessful well or that begins production:
    (1) Before the date which is 5 years after the lease issuance date 
on a non-converted lease; or
    (2) Before May 3, 2009, on all other leases located in water partly 
or entirely less than 200 meters deep; or
    (3) Before May 3, 2013, on a lease that is located in water 
entirely more than 200 meters and entirely less than 400 meters deep.
    Phase 3 ultra-deep well means an ultra-deep well for which drilling 
began on or after May 18, 2007, and that begins production:
    (1) On or after the date which is 5 years after the lease issuance 
date on a non-converted lease; or
    (2) On or after May 3, 2009, on all other leases located in water 
partly or entirely less than 200 meters deep; or
    (3) On or after May 3, 2013, on a lease that is located in water 
entirely more

[[Page 64465]]

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 issuance date from a reservoir that has not produced from a deep 
well on any lease; or
    (3) On a lease that is located in water entirely more than 200 
meters but entirely less than 400 meters deep, a deep well for which 
drilling began on or after May 18, 2007, that produces natural gas 
(other than test production), including gas associated with oil 
production before May 3, 2013, and for which you have met the 
requirements prescribed in Sec.  203.44.
    Qualified ultra-deep well means:
    (1) On a lease that is located in water partly or entirely less 
than 200 meters deep that is not a non-converted lease, an ultra-deep 
well for which drilling began on or after March 26, 2003, that produces 
natural gas (other than test production), including gas associated with 
oil production, and for which you have met the requirements prescribed 
in Sec.  203.35 or Sec.  203.44, as applicable; or
    (2) On a lease that is located in water entirely more than 200 
meters and entirely less than 400 meters deep, or on a non-converted 
lease, an ultra-deep well for which drilling began on or after May 18, 
2007, that produces natural gas (other than test production), including 
gas associated with oil production, and for which you have met the 
requirements prescribed in Sec.  203.35.
    Qualified well means either a qualified deep well or a qualified 
ultra-deep well.
    Redetermination means our reconsideration of our determination on 
royalty relief because you request it after:
    (1) We have rejected your application;
    (2) We have granted relief but you want a larger suspension volume;
    (3) We withdraw approval; or
    (4) You renounce royalty relief.
    Renounce means action you take to give up relief after we have 
granted it and before you start production.
    Reservoir means an underground accumulation of oil or natural gas, 
or both, characterized by a single pressure system and segregated from 
other such accumulations.
    Royalty suspension (RS) lease means a lease that:
    (1) Is issued as part of an OCS lease sale held after November 28, 
2000;
    (2) Is in locations or planning areas specified in a particular 
Notice of OCS Lease Sale offering that lease; and
    (3) Is offered subject to a royalty suspension specified in a 
Notice of OCS Lease Sale published in the Federal Register.
    Royalty suspension supplement (RSS) means a royalty suspension 
volume resulting from drilling a certified unsuccessful well that is 
applied to future natural gas and oil production generated at any 
drilling depth on, or allocated under a BSEE-approved unit agreement 
to, the same lease.
    Royalty suspension volume (RSV) means a volume of production from a 
lease that is not subject to royalty under the provisions of this part.
    Sidetrack means, for the purpose of this subpart, a well resulting 
from drilling an additional hole to a new objective bottom-hole 
location by leaving a previously drilled hole. A sidetrack also 
includes drilling a well from a platform slot reclaimed from a 
previously drilled well or re-entering and deepening a previously 
drilled well. A bypass from a sidetrack (e.g., drilling around material 
blocking the hole, or to straighten crooked holes) is part of the 
sidetrack.
    Sidetrack measured depth means the actual distance or length in 
feet a sidetrack is drilled beginning where it exits a previously 
drilled hole to the bottom hole of the sidetrack, that is, to its total 
depth.
    Sunk costs for an authorized field means the after-tax eligible 
costs that you (not third parties) incur for exploration, development, 
and production from the spud date of the first discovery on the field 
to the date we receive your complete application for royalty relief. 
The discovery well must be qualified as producible under 30 CFR part 
550, subpart A. Sunk costs include the rig mobilization and material 
costs for the discovery well that you incurred before its spud date.
    Sunk costs for an expansion or development project means the after-
tax eligible costs that you (not third parties) incur for only the 
first well that encounters hydrocarbons in the reservoir(s) included in 
the application and that meets the producibility requirements under 30 
CFR part 550, subpart A on each lease participating in the application. 
Sunk costs include rig mobilization and material costs for the 
discovery wells that you incurred before their spud dates.
    Ultra-deep well means either an original well or a sidetrack 
completed with a perforated interval the top of which is at least 
20,000 feet TVD SS. An ultra-deep well subsequently re-perforated less 
than 20,000 feet TVD SS in the same reservoir is still an ultra-deep 
well.
    Withdraw means action we take on a field that has qualified for 
relief if you have not met one or more of the performance conditions.


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

    The Outer Continental Shelf (OCS) Lands Act, 43 U.S.C. 1337, as 
amended by the OCS Deep Water Royalty Relief Act (DWRRA), Public Law 
104-58 and the Energy Policy Act of 2005, Public Law 109-058 authorizes 
us to grant royalty relief in four situations.
    (a) Under 43 U.S.C. 1337(a)(3)(A), we may reduce or eliminate any 
royalty or a net profit share specified for an OCS lease to promote 
increased production.
    (b) Under 43 U.S.C. 1337(a)(3)(B), we may reduce, modify, or 
eliminate any royalty or net profit share to promote development, 
increase production, or encourage production of marginal resources on 
certain leases or categories of leases. This authority is restricted to 
leases in the GOM that are west of 87 degrees, 30 minutes West 
longitude, and in the planning areas offshore Alaska.
    (c) Under 43 U.S.C. 1337(a)(3)(C), we may suspend royalties for 
designated volumes of new production from any lease if:
    (1) Your lease is in deep water (water at least 200 meters deep);
    (2) Your lease is in designated areas of the GOM (west of 87 
degrees, 30 minutes West longitude);
    (3) Your lease was acquired in a lease sale held before the DWRRA 
(before November 28, 1995);

[[Page 64466]]

    (4) We find that your new production would not be economic without 
royalty relief; and
    (5) Your lease is on a field that did not produce before enactment 
of the DWRRA, or if you propose a project to significantly expand 
production under a Development Operations Coordination Document (DOCD) 
or a supplementary DOCD, that the Bureau of Ocean Energy Management 
(BOEM) approved after November 28, 1995.
    (d) Under 42 U.S.C. 15904-15905, we may suspend royalties for 
designated volumes of gas production from deep and ultra-deep wells on 
a lease if:
    (1) Your lease is in shallow water (water less than 400 meters 
deep) and you produce from an ultra-deep well (top of the perforated 
interval is at least 20,000 feet TVD SS) or your lease is in waters 
entirely more than 200 meters and entirely less than 400 meters deep 
and you produce from a deep well (top of the perforated interval is at 
least 15,000 feet TVD SS);
    (2) Your lease is in the designated area of the GOM (wholly west of 
87 degrees, 30 minutes west longitude); and
    (3) Your lease is not eligible for deep water royalty relief.


Sec.  203.2  How can I obtain royalty relief?

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

----------------------------------------------------------------------------------------------------------------
                                                                                     Then we may grant you . . .
        If you have a lease . . .                      And if you . . .
----------------------------------------------------------------------------------------------------------------
(a) With earnings that cannot sustain      Would abandon otherwise potentially       A reduced royalty rate on
 production (i.e., End-of-life lease),      recoverable resources but seek to         current monthly production
                                            increase production by operating beyond   and a higher royalty rate
                                            the point at which the lease is           on additional monthly
                                            economic under the existing royalty       production (see Sec.  Sec.
                                            rate,                                       203.50 through 203.56).
(b) Located in a designated GOM deep       Propose an expansion project and can      A royalty suspension for a
 water area (i.e., 200 meters or greater)   demonstrate your project is uneconomic    minimum production volume
 and acquired in a lease sale held before   without royalty relief,                   plus any additional
 November 28, 1995, or after November 28,                                             production large enough to
 2000,                                                                                make the project economic
                                                                                      (see Sec.  Sec.   203.60
                                                                                      through 203.79).
(c) Located in a designated GOM deep       Are on a field from which no current pre- A royalty suspension for a
 water area and acquired in a lease sale    Act lease produced (other than test       minimum production volume
 held before November 28, 1995 (Pre-Act     production) before November 28, 1995,     plus any additional volume
 lease),                                    (Authorized field,)                       needed to make the field
                                                                                      economic (see Sec.  Sec.
                                                                                      203.60 through 203.79).
(d) Located in a designated GOM deep       Propose a development project and can     A royalty suspension for a
 water area and acquired in a lease sale    demonstrate that the suspension volume,   minimum production volume
 held after November 28, 2000,              if any, for your lease is not enough to   plus any additional volume
                                            make development economic,                needed to make your
                                                                                      project economic (see Sec.
                                                                                       Sec.   203.60 through
                                                                                      203.79).
(e) Where royalty relief would recover     Are not eligible to apply for end-of-     A royalty modification in
 significant additional resources or,       life or deep water royalty relief, but    size, duration, or form
 offshore Alaska or in certain areas of     show us you meet certain eligibility      that makes your lease or
 the GOM, would enable development,         conditions,                               project economic (see Sec.
                                                                                        203.80).
(f) Located in a designated GOM shallow    Drill a deep well on a lease that is not  A royalty suspension for a
 water area and acquired in a lease sale    eligible for deep water royalty relief    volume of gas produced
 held before January 1, 2001, or after      and you have not previously produced      from successful deep and
 January 1, 2004, or have exercised an      oil or gas from a deep well or an ultra-  ultra-deep wells, or, for
 option to substitute for royalty relief    deep well,                                certain unsuccessful deep
 in your lease terms,                                                                 and ultra-deep wells, a
                                                                                      smaller royalty suspension
                                                                                      for a volume of gas or oil
                                                                                      produced by all wells on
                                                                                      your lease (see Sec.  Sec.
                                                                                        203.40 through 203.49).
(g) Located in a designated GOM shallow    Drill and produce gas from an ultra-deep  A royalty suspension for a
 water area,                                well on a lease that is not eligible      volume of gas produced
                                            for deep water royalty relief and you     from successful ultra-deep
                                            have not previously produced oil or gas   and deep wells on your
                                            from an ultra-deep well,                  lease (see Sec.  Sec.
                                                                                      .203.30 through 203.36).
(h) Located in planning areas offshore     Propose an expansion project or propose   A royalty suspension for a
 Alaska,                                    a development project and can             minimum production volume
                                            demonstrate that the project is           plus any additional volume
                                            uneconomic without relief or that the     needed to make your
                                            suspension volume, if any, for your       project economic (see Sec.
                                            lease is not enough to make development    Sec.   203.60, 203.62,
                                            economic,                                 203.67 through 203.70,
                                                                                      203.73, and 203.76 through
                                                                                      203.79).
----------------------------------------------------------------------------------------------------------------

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

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


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.

[[Page 64467]]

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

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

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

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

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

 
----------------------------------------------------------------------------------------------------------------
                                                                                       Deep water
                                                          End-of-life  -----------------------------------------
              Redetermination conditions                     lease       Expansion     Pre-act      Development
                                                                          project       lease         project
----------------------------------------------------------------------------------------------------------------
(1) After 12 months under current rate, criteria same               X   ...........  ...........  ..............
 as for approval......................................
(2) For material change in geologic data, prices,       ..............           X            X               X
 costs, 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 64468]]



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

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

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

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

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

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

    (a) The Office of Management and Budget (OMB) has approved the 
information collection requirements in this part under 44 U.S.C. 3501 
et seq., and assigned OMB Control Number 1010-0071. The title of this 
information collection is ``30 CFR part 203, Relief or Reduction in 
Royalty Rates.''
    (b) BSEE collects this information to make decisions on the 
economic viability of leases requesting a suspension or elimination of 
royalty or net profit share. Responses are required to obtain a benefit 
or are mandatory according to 43 U.S.C. 1331 et seq. BSEE will protect 
information considered proprietary under applicable law and under 
regulations at Sec.  203.61, ``How do I assess my chances for getting 
relief?'' and 30 CFR 250.197, ``Data and information to be made 
available to the public or for limited inspection.''
    (c) An agency may not conduct or sponsor, and a person is not 
required to respond to a collection of information unless it displays a 
currently valid OMB control number.
    (d) Send comments regarding any aspect of the collection of 
information under this part, including suggestions for reducing the 
burden, to the Information Collection Clearance Officer, Bureau of 
Safety and Environmental Enforcement, 381 Elden Street, Herndon, VA 
20170.

Subpart B--OCS Oil, Gas, and Sulfur General

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


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

    Your lease may receive a royalty suspension volume (RSV) under 
Sec. Sec.  203.31 through 203.36 if the lease meets all the 
requirements of this section.

[[Page 64469]]

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


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

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

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

     (b)(1) This paragraph applies if your lease:
    (i) Has produced gas or oil from a deep well with a perforated 
interval the top of which is less than 18,000 feet TVD SS;
    (ii) Was issued in a lease sale held between January 1, 2004, and 
December 31, 2005; and
    (iii) The terms of your lease expressly incorporate the provisions 
of Sec. Sec.  203.41 through 203.47 as they existed at the time the 
lease was issued.
    (2) Subject to the administrative requirements of Sec.  203.35 and 
the price conditions in Sec.  203.36, your qualified well earns your 
lease an RSV shown in the following table in BCF or MCF as prescribed 
in Sec.  203.33:

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

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

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

[[Page 64470]]

which is 16,000 feet TVD SS. Your 16,000-foot well earns no RSV 
because it is on a lease that already has a producing well at least 
18,000 feet subsea (see Sec.  203.42(a)), but any remaining RSV 
earned by the ultra-deep well would also be applied to production 
from the deep well as prescribed in Sec.  203.33(a)(2), or Sec.  
203.33(b)(2) if your lease is part of a unit and Sec.  203.43(a)(2), 
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.


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

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

    Example:  The east half of your lease A is unitized with all of 
lease B. There is one qualified phase 2 ultra-deep well on the non-
unitized portion of lease A that earns lease A an RSV of 35 BCF 
under Sec.  203.31, one qualified deep well on the unitized portion

[[Page 64471]]

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


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

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


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

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

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

[[Page 64472]]

 
(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 
TVD SS) on a lease located in 325 meters of water with no prior 
production from any deep well and no deep water royalty relief. The 
ultra-deep well would be a phase 2 ultra-deep well (see definition 
in Sec.  203.0), and would earn the lease an RSV of 35 BCF under 
Sec. Sec.  203.30 and 203.31. Further assume that the average daily 
closing NYMEX natural gas price exceeds $4.55 per MMBtu (adjusted 
for inflation after 2007) but does not exceed $10.15 per MMBtu 
(adjusted for inflation after 2007) during 2010. Because the lease 
is located in more than 200 but less than 400 meters of water, the 
$4.55 per MMBtu price threshold applies to the whole RSV (see 
paragraph (a)(2)(v) of this section), and the lessee will owe 
royalty on all gas produced from the ultra-deep well in 2010.

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

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


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

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


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

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

[[Page 64473]]



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

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

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

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

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

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

    Example 1: If you have a qualified deep well that is an original 
well with a perforated interval the top of which is 16,000 feet TVD 
SS, your lease earns an RSV of 15 BCF under paragraph (b)(1) of this 
section. This RSV must be applied to gas production from all 
qualified wells on your lease, as prescribed in Sec. Sec.  203.43 
and 203.48. However, if the top of the perforated interval is 18,500 
feet TVD SS, the RSV is 25 BCF according to paragraph (b)(3) of this 
section.
    Example 2: If you have a qualified deep well that is a 
sidetrack, with a perforated interval the top of which is 16,000 
feet TVD SS and a sidetrack measured depth of 6,789 feet, we round 
the measured depth to 6,800 feet and your lease earns an RSV of 8.08 
BCF under paragraph (b)(2) of this section. This RSV would be 
applied to gas production from all qualified wells on your lease, as 
prescribed in Sec. Sec.  203.43 and 203.48.
    Example 3: If you have a qualified deep well that is a 
sidetrack, with a perforated interval the top of which is 16,000 
feet TVD SS and a sidetrack measured depth of 19,500 feet, your 
lease earns an RSV of 15 BCF. This RSV would be applied to gas 
production from all qualified wells on your lease, as prescribed in 
Sec. Sec.  203.43 and 203.48, even though 4 BCF plus 600 MCF per 
foot of sidetrack measured depth equals 15.7 BCF because paragraph 
(b)(2) of this section limits the RSV for a sidetrack at the amount 
an original well to the same depth would earn.
    Example 4: If you have drilled and produced a deep well with a 
perforated interval the top of which is 16,000 feet TVD SS before 
March 26, 2003 (and the well therefore is not a qualified well and 
has earned no RSV under this section), and later drill:
    (i) A deep well with a perforated interval the top of which is 
17,000 feet TVD SS, your lease earns no RSV (see paragraph (c)(1) of 
this section);
    (ii) A qualified deep well that is an original well with a 
perforated interval the top of which is 19,000 feet TVD SS, your 
lease earns an RSV of 10 BCF under paragraph (c)(2) of this section. 
This RSV would be applied to gas production from qualified wells on 
your lease, as prescribed in Sec. Sec.  203.43 and 203.48; or
    (iii) A qualified deep well that is a sidetrack with a 
perforated interval the top of which is 19,000 feet TVD SS, that has 
a sidetrack measured depth of 7,000 feet, your lease earns an RSV of 
8.2 BCF under paragraph (c)(3) of this section. This RSV would be 
applied to gas production from qualified wells on your lease, as 
prescribed in Sec. Sec.  203.43 and 203.48.
    Example 5: If you have a qualified deep well that is an original 
well with a perforated interval the top of which is 16,000 feet TVD 
SS, and later drill a second qualified well that is an original well 
with a perforated interval the top of which is 19,000 feet TVD SS, 
we increase the total RSV for your lease from 15 BCF to 25 BCF under 
paragraph (c)(2) of this section. We will apply that RSV to gas 
production from all qualified wells on your lease, as prescribed in 
Sec. Sec.  203.43 and 203.48. If the second well has a perforated 
interval the top of which is 22,000 feet TVD SS (instead of 19,000 
feet), the total RSV for your lease would increase to 25 BCF only in

[[Page 64474]]

2 situations: (1) If the second well was a phase 1 ultra-deep well, 
i.e., if drilling began before May 18, 2007, or (2) the exception in 
Sec.  203.31(b) applies. In both situations, your lease must be 
partly or entirely in less than 200 meters of water and production 
must begin on this well before May 3, 2009. If drilling of the 
second well began on or after May 18, 2007, the second well would be 
qualified as a phase 2 or phase 3 ultra-deep well and, unless the 
exception in Sec.  203.31(b) applies, would not earn any additional 
RSV (as prescribed in Sec.  203.30), so the total RSV for your lease 
would remain at 15 BCF.
    Example 6:  If you have a qualified deep well that is a 
sidetrack, with a perforated interval the top of which is 16,000 
feet TVD SS and a sidetrack measured depth of 4,000 feet, and later 
drill a second qualified well that is a sidetrack, with a perforated 
interval the top of which is 19,000 feet TVD SS and a sidetrack 
measured depth of 8,000 feet, we increase the total RSV for your 
lease from 6.4 BCF [4 + (600 * 4,000)/1,000,000] to 15.2 BCF {6.4 + 
[4 + (600 * 8,000)/1,000,000)]{time}  under paragraphs (b)(2) and 
(c)(3) of this section. We would apply that RSV to gas production 
from all qualified wells on your lease, as prescribed in Sec. Sec.  
203.43 and 203.48. The difference of 8.8 BCF represents the RSV 
earned by the second sidetrack that has a perforated interval the 
top of which is deeper than 18,000 feet TVD SS.


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

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

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

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


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

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

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

[[Page 64475]]

until the 15 BCF RSV is fully utilized according to paragraph (b)(2) 
of this section.

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

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

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


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

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


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

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

------------------------------------------------------------------------
                                            Then your lease earns an RSS
                                              on this volume of oil and
 If you have a certified unsuccessful well  gas production as prescribed
                that is:--                    in this section and Sec.
                                                      203.46:--
------------------------------------------------------------------------
(1) An original well and your lease has     5 BCFE.
 not produced gas or oil from a deep well
 or an ultra-deep well,

[[Page 64476]]

 
(2) A sidetrack (with a sidetrack measured  0.8 BCFE plus 120 MCFE times
 depth of at least 10,000 feet) and your     sidetrack measured depth
 lease has not produced gas or oil from a    (rounded to the nearest 100
 deep well or an ultra-deep well,            feet) but no more than 5
                                             BCFE.
(3) An original well or a sidetrack (with   2 BCFE.
 a sidetrack measured depth of at least
 10,000 feet) and your lease has produced
 gas or oil from a deep well with a
 perforated interval the top of which is
 from 15,000 to less than 18,000 feet TVD
 SS,
------------------------------------------------------------------------

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

    Example 1: If you drill a certified unsuccessful well that is an 
original well to a target 19,000 feet TVD SS, your lease earns an 
RSS of 5 BCFE that would be applied to gas and oil production if 
your lease has not previously produced from a deep well or an ultra-
deep well, or you earn an RSS of 2 BCFE of gas and oil production if 
your lease has previously produced from a deep well with a 
perforated interval from 15,000 to less than 18,000 feet TVD SS, as 
prescribed in Sec.  203.46.
    Example 2: If you drill a certified unsuccessful well that is a 
sidetrack that reaches a target 19,000 feet TVD SS, that has a 
sidetrack measured depth of 12,545 feet, and your lease has not 
produced gas or oil from any deep well or ultra-deep well, BSEE 
rounds the sidetrack measured depth to 12,500 feet and your lease 
earns an RSS of 2.3 BCFE of gas and oil production as prescribed in 
Sec.  203.45.

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


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

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

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

    (c) If you have no current production on which to apply the RSS 
allowed under Sec.  203.45, your RSS applies to the earliest subsequent 
production of gas and oil from, or allocated under a BSEE-approved unit 
agreement to, your lease.
    (d) Unused royalty suspension supplements transfer to a successor 
lessee and expire with the lease.
    (e) You may not apply the RSS allowed under Sec.  203.45 to 
production from any other lease, except for production allocated to 
your lease from a BSEE-approved unit agreement. If your certified 
unsuccessful well is on a lease subject to a BSEE-approved unit 
agreement, the lessees of other leases in the unit may not apply any 
portion of the RSS for your lease to production from the other leases 
in the unit.
    (f) You must begin or resume paying royalties when cumulative gas 
and oil production from, or allocated under a BSEE-approved unit 
agreement to, your lease (excluding any gas produced from qualified 
wells subject to a royalty suspension volume allowed under Sec.  
203.41) reaches the applicable royalty suspension supplement. For the 
month in which the cumulative production reaches this royalty 
suspension supplement, you owe royalties on the portion of gas or oil 
production that exceeds the amount of the royalty

[[Page 64477]]

suspension supplement remaining at the beginning of that month.


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

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


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

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

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

    (b) Determine the threshold price for any calendar year after 2007 
by adjusting the threshold price in the previous year by the percentage 
that the implicit price deflator for the gross domestic product, as 
published by the Department of Commerce, changed during the calendar 
year.
    (c) You must pay any royalty due under this section no later than 
March 31 of the year following the calendar year for which you owe 
royalty. If you do not pay by that date, you must pay late payment 
interest under 30 CFR 1218.54 from April 1 until the date of payment.
    (d) Production volumes on which you must pay royalty under this 
section count as part of your RSV and RSS.


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

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

Royalty Relief for End-of-Life Leases


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

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


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

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


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

    (a) To qualify for relief, you must demonstrate that the sum of 
royalty payments over the 12 qualifying months exceeds 75 percent of 
the sum of net revenues (before-royalty revenues minus allowable costs, 
as defined in Sec.  203.84).
    (b) To re-qualify for relief, e.g., either applying for additional 
relief on top of relief already granted, or applying for

[[Page 64478]]

relief sometime after your earlier agreement terminated, you must 
demonstrate that:
    (1) You have met the criterion listed in paragraph (a) of this 
section, and
    (2) The 12 required qualifying months of operation have occurred 
under the current royalty arrangement.


Sec.  203.53  What relief will BSEE grant?

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


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

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


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

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


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

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

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


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

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


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

    You may ask for a nonbinding assessment (a formal opinion on 
whether a field would qualify for royalty relief) before turning in 
your first complete application on an authorized field. This field must 
have a qualifying well under 30 CFR part 550, subpart A, or be on a 
lease that has allocated production under an approved unit agreement.
    (a) To request a nonbinding assessment, you must:
    (1) Submit a draft application in the format and detail specified 
in guidance from the BSEE regional office for the GOM;
    (2) Propose to drill at least one more appraisal well if you get a 
favorable assessment; and
    (3) Pay a fee under Sec.  203.3.
    (b) You must wait at least 90 days after receiving our assessment 
to apply for relief under Sec.  203.62.
    (c) This assessment is not binding because a complete application 
may contain more accurate information that does not support our 
original assessment. It will help you decide whether your proposed 
inputs for evaluating economic viability and your supporting data and 
assumptions are adequate.


Sec.  203.62  How do I apply for relief?

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


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

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

[[Page 64479]]

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

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


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

    (a) We will determine within 20 working days if your application 
for royalty relief is complete. If your application is incomplete, we 
will explain in writing what it needs. If you withdraw a complete 
application, you may reapply.
    (b) We will evaluate your first application on a field within 180 
days, evaluate your first application on a development project or an 
expansion project within 150 days and evaluate a redetermination under 
Sec.  203.75 within 120 days after we determine that it is complete.
    (c) We may ask to extend the review period for your application 
under the conditions in the following table.

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

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


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

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

----------------------------------------------------------------------------------------------------------------
  If you apply for royalty      And we do not decide within the time
         relief for                          specified,                              As long as you
----------------------------------------------------------------------------------------------------------------
(a) An authorized field,      You get the minimum suspension volumes    Abide by Sec.  Sec.   203.70 and 203.76.
                               specified in Sec.   203.69,
(b) An expansion project,     You get a royalty suspension for the      Abide by Sec.  Sec.   203.70 and 203.76.
                               first year of production,
(c) A development project,    You get a royalty suspension for initial  Abide by Sec.  Sec.   203.70 and 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,
----------------------------------------------------------------------------------------------------------------

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

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


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

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

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

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

[[Page 64480]]

or the regulations of this chapter (e.g., fuel gas).
    (a) For authorized fields, the minimum royalty-suspension volumes 
are:
    (1) 17.5 million barrels of oil equivalent (MMBOE) for fields in 
200 to 400 meters of water;
    (2) 52.5 MMBOE for fields in 400 to 800 meters of water; and
    (3) 87.5 MMBOE for fields in more than 800 meters of water.
    (b) For development projects, any relief we grant applies only to 
project wells and replaces the royalty relief, if any, with which we 
issued your lease.
    (c) If your project is economic given the royalty relief with which 
we issued your lease, we will reject the application.
    (d) If the lease has earned or may earn deep gas royalty relief 
under Sec. Sec.  203.40 through 203.49 or ultra-deep gas royalty relief 
under Sec. Sec.  203.30 through 203.36, we will take the deep gas 
royalty relief or ultra-deep gas royalty relief into account in 
determining whether further royalty relief for a development project is 
necessary for production to be economic.
    (e) If neither paragraph (c) nor (d) of this section apply, the 
minimum royalty suspension volumes are as shown in the following table:

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

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


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

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

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

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

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

----------------------------------------------------------------------------------------------------------------
              If . . .                             Then . . .                             And . . .
----------------------------------------------------------------------------------------------------------------
(1) We assign an eligible lease to   We will not change your authorized     Production from the assigned
 your authorized field after we       field's royalty suspension volume      eligible lease(s) counts toward the
 approve relief,                      determined under Sec.   203.69,        royalty 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 30 CFR 560.114.

[[Page 64481]]

 
(2) We assign a pre-Act or post-     We will not change your field's        The assigned lease(s) may share in
 November 2000 deep water lease to    royalty suspension volume,             any remaining royalty relief by
 your field after we approve your                                            filing the short-form application
 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 of your authorized   (i) You toll the time period for
 you operate to your field while we   field, we will take into account the   evaluation until you modify your
 are evaluating your application,     value of any royalty relief the        application to be consistent with
                                      added lease already has under 30 CFR   the newly constituted field;
                                      560.114 or its lease document. If we  (ii) We have an additional 60 days
                                      find your authorized field still       to review the new information; and
                                      needs additional royalty suspension   (iii) The assigned pre-Act lease or
                                      volume, that volume will be at least   royalty suspension lease shares the
                                      the combined royalty suspension        royalty suspension we grant to the
                                      volume to which all added leases on    newly constituted field. An
                                      the field are entitled, or the         eligible lease does not share the
                                      minimum suspension volume of the       royalty suspension we grant to the
                                      authorized field, whichever is         new field. If you do not agree to
                                      greater,                               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 30 CFR 560.114.
(4) We assign another operator's     We will change your field's minimum    (i) You both toll the time period
 lease to your field while we are     suspension volume provided the         for evaluation until both of you
 evaluating your application,         assigned lease joins the application   modify your application to be
                                      and is entitled to a larger minimum    consistent with the new field;
                                      suspension volume,                    (ii) We have an additional 60 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.
(5) We reassign a well on a pre-     The past production from the well      For any field based relief, the past
 Act, eligible, or royalty            counts toward the royalty suspension   production for that well will not
 suspension lease from field A to     volume that we grant under Sec.        count toward any royalty suspension
 field B,                             203.69 to field B,                     volume that we grant under Sec.
                                                                             203.69 to field A. Moreover, past
                                                                             production from that well will
                                                                             count toward the royalty suspension
                                                                             volume applicable for the lease
                                                                             under 30 CFR 560.114 if the well is
                                                                             on an eligible lease or under 30
                                                                             CFR 560.124 if the well is on a
                                                                             royalty suspension lease.
----------------------------------------------------------------------------------------------------------------

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


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

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


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

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


Sec.  203.74  When will BSEE reconsider its determination?

    You may request a redetermination after we withdraw approval or 
after you renounce royalty relief, unless we withdraw approval due to 
your providing false or intentionally inaccurate information. Under 
certain conditions you may also request a redetermination if we deny 
your application or if you want your approved royalty suspension volume 
to change. In these instances, to be eligible for a redetermination, at 
least one of the following four conditions must occur.
    (a) You have significant new G&G data and you previously have not 
either requested a redetermination or reapplied for relief after we 
withdrew

[[Page 64482]]

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.
    (c) Your current reference price decreases by more than 25 percent 
from your base reference price as calculated under this paragraph.
    (1) Your current reference price is a weighted-average of daily 
closing prices on the NYMEX for light sweet crude oil and natural gas 
over the most recent full 12 calendar months;
    (2) Your base reference price is a weighted average of daily 
closing prices on the NYMEX for light sweet crude oil and natural gas 
for the full 12 calendar months preceding the date of your most 
recently approved application for this royalty relief; and
    (3) The weighting factors are the proportions of the total 
production volume (in BOE) for oil and gas associated with the most 
likely scenario (identified in Sec. Sec.  203.85 and 203.88) from your 
most recently approved application for this royalty relief.
    (d) Before starting to build your development and production 
system, you have revised your estimated development costs, and they are 
more than 120 percent of the eligible development costs associated with 
the most likely scenario from your most recently approved application 
for this royalty relief.


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

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


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

    We will withdraw approval of relief for any of the following 
reasons.
    (a) You change the type of development system proposed in your 
application (e.g., change from a fixed platform to floating production 
system, or from an independent development and production system to one 
with subsea wells tied back to a host production facility, etc.).
    (b) You do not start building the proposed development and 
production system within 18 months of the date we approved your 
application, unless the BSEE Director grants you an extension under 
Sec.  203.79(c). If you start building the proposed system and then 
suspend its construction before completion, and you do not restart 
continuous building of the proposed system within 18 months of our 
approval, we will withdraw the relief we granted.
    (c) Your actual development costs are less than 80 percent of the 
eligible development costs estimated in your application's most likely 
scenario, and you do not report that fact in your post-production 
development report (Sec.  203.70). Development costs are those 
expenditures defined in Sec.  203.89(b) incurred between the 
application submission date and start of production. If you report this 
fact in the post-production development report, you may retain the 
lesser of 50 percent of the original royalty suspension volume or 50 
percent of the median of the distribution of the potentially 
recoverable resources anticipated in your application.
    (d) We granted you a royalty-suspension volume after you qualified 
for a redetermination under Sec.  203.74(c), and we find out your 
actual development costs are less than 90 percent of the eligible 
development costs associated with your application's most likely 
scenario. Development costs are those expenditures defined in Sec.  
203.89(b) incurred between your application submission date and start 
of production.
    (e) You do not send us the fabrication confirmation report or the 
post-production development report, or you provide false or 
intentionally inaccurate information that was material to our granting 
royalty relief under this section. You must pay royalties and late-
payment interest determined under 30 U.S.C. 1721 and 30 CFR 1218.54 on 
all volumes for which you used the royalty suspension. You also may be 
subject to penalties under other provisions of law.


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

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


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

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

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


[[Page 64483]]

    (b) An exception may occur if we determine that the price 
thresholds in paragraphs (a)(2) or (a)(3) of this section mean the 
royalty suspension volume set under Sec.  203.69 and in lease terms 
would provide inadequate encouragement to increase production or 
development, in which circumstance we could specify a different set of 
price thresholds on a case-by-case basis.
    (c) Suppose your base oil price threshold set under paragraph (a) 
is $28.00 per barrel, and the daily closing NYMEX light sweet crude oil 
prices for the previous calendar year exceeds $28.00 per barrel, as 
adjusted in paragraph (h) of this section. In this case, we retract the 
royalty relief authorized in this subpart and you must:
    (1) Pay royalties on all oil production for the previous year at 
the lease stipulated royalty rate plus interest (under 30 U.S.C. 1721 
and 30 CFR 1218.54) by March 31 of the current calendar year, and
    (2) Pay royalties on all your oil production in the current year.
    (d) Suppose your base gas price threshold set under paragraph (a) 
is $3.50 per million British thermal units (Btu), and the daily closing 
NYMEX light sweet crude oil prices for the previous calendar year 
exceeds $3.50 per million Btu, as adjusted in paragraph (h) of this 
section. In this case, we retract the royalty relief authorized in this 
subpart and you must:
    (1) Pay royalties on all gas production for the previous year at 
the lease stipulated royalty rate plus interest (under 30 U.S.C. 1721 
and 30 CFR 1218.54) by March 31 of the current calendar year, and
    (2) Pay royalties on all your gas production in the current year.
    (e) Production under both paragraphs (c) and (d) of this section 
counts as part of the royalty-suspension volume.
    (f) You are entitled to a refund or credit, with interest, of 
royalties paid on any production (that counts as part of the royalty-
suspension volume):
    (1) Of oil if the arithmetic average of the closing prices for the 
current calendar year is $28.00 per barrel or less, as adjusted in 
paragraph (h) of this section, and
    (2) Of gas if the arithmetic average of the closing natural gas 
prices for the current calendar year is $3.50 per million Btu or less, 
as adjusted in paragraph (h) of this section.
    (g) You must follow our regulations in the Office of Natural 
Resources Revenue, 30 CFR chapter XII, for receiving refunds or 
credits.
    (h) We change the prices referred to in paragraphs (c), (d), and 
(f) of this section periodically. For pre-Act leases, these prices 
change during each calendar year after 1994 by the percentage that the 
implicit price deflator for the gross domestic product changed during 
the preceding calendar year. For post-November 2000 deepwater leases, 
these prices change as indicated in the lease instrument or in the 
Notice of Sale under which we issued the lease.


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

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


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

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

Required Reports


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

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

----------------------------------------------------------------------------------------------------------------
                                                                                   Deep water
                                                End-of-life   --------------------------------------------------
              Required reports                     lease          Expansion                        Development
                                                                   project       Pre-act lease       project
----------------------------------------------------------------------------------------------------------------
(1) Administrative information Report.......               X                X                X                X
(2) Net revenue & relief justification                     X   ...............  ...............  ...............
 report.....................................

[[Page 64484]]

 
(3) Economic viability & relief               ...............               X                X                X
 justification report (RSVP model inputs
 justified by other required reports).......
(4) G&G report..............................  ...............               X                X                X
(5) Engineering report......................  ...............               X                X                X
(6) Production report.......................  ...............               X                X                X
(7) Deep water cost report..................  ...............               X                X                X
(8) Fabricator's confirmation report........  ...............               X                X                X
(9) Post-production development report......  ...............               X                X                X
----------------------------------------------------------------------------------------------------------------

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


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

    The Office of Management and Budget (OMB) approved the information 
collection requirements in part 203 under 44 U.S.C. 3501 et seq., and 
assigned OMB control number 1010-0071.
    (a) We use the information to determine whether royalty relief will 
result in production that wouldn't otherwise occur. We rely largely on 
your information to make these determinations.
    (1) Your application for royalty relief must contain enough 
information on finances, economics, reservoirs, G&G characteristics, 
production, and engineering estimates for us to determine whether:
    (i) We should grant relief under the law, and
    (ii) The requested relief will ultimately recover more resources 
and return a reasonable profit on project investments.
    (2) Your fabricator confirmation and post-production development 
reports must contain enough information for us to verify that your 
application reasonably represented your plans.
    (b) Applicants (respondents) are Federal OCS oil and gas lessees. 
Applications are required to obtain or retain a benefit. Therefore, if 
you apply for royalty relief, you must provide this information. We 
will protect information considered proprietary under applicable law 
and under regulations at Sec.  203.63 and 30 CFR part 250.
    (c) The Paperwork Reduction Act of 1995 requires us to inform you 
that we may not conduct or sponsor, and you are not required to respond 
to, a collection of information unless it displays a currently valid 
OMB control number.
    (d) Send comments regarding any aspect of the collection of 
information under this part, including suggestions for reducing the 
burden, to the Information Collection Clearance Officer, Bureau of 
Safety and Environmental Enforcement, 381 Elden Street, Herndon, VA 
20170.


Sec.  203.83  What is in an administrative information report?

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


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

    This report presents cash flow data for 12 qualifying months, using 
the format specified in the ``Guidelines for the Application, Review, 
Approval, and Administration of Royalty Relief for End-of-Life 
Leases'', U.S. Department of the Interior, BSEE. Qualifying months for 
an oil and gas lease are the most recent 12 months out of the last 15 
months that you produced at least 100 BOE per day on average. 
Qualifying months for other than oil and gas leases are the most recent 
12 of the last 15 months having some production.
    (a) The cash flow table you submit must include historical data 
for:
    (1) Lease production subject to royalty;
    (2) Total revenues;
    (3) Royalty payments out of production;
    (4) Total allowable costs; and
    (5) Transportation and processing costs.
    (b) Do not include in your cash flow table the non-allowable costs 
listed at 30 CFR 1220.013 or:
    (1) OCS rental payments on the lease(s) in the application;
    (2) Damages and losses;
    (3) Taxes;
    (4) Any costs associated with exploratory activities;

[[Page 64485]]

    (5) Civil or criminal fines or penalties;
    (6) Fees for your royalty relief application; and
    (7) Costs associated with existing obligations (e.g., royalty 
overrides or other forms of payment for acquiring the lease, 
depreciation on previously acquired equipment or facilities).
    (c) We may, in reviewing and evaluating your application, disallow 
costs when you have not shown they are necessary to operate the lease, 
or if they are inconsistent with end-of-life operations.


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

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


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

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

[[Page 64486]]

will be related to the most likely development and production scenario; 
and, the high end range will be consistent with the optimistic 
development and production scenario.


Sec.  203.87  What is in an engineering report?

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


Sec.  203.88  What is in a production report?

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


Sec.  203.89  What is in a cost report?

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


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

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


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

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

[[Page 64487]]

Subpart C--Federal and Indian Oil [Reserved]

Subpart D--Federal and Indian Gas [Reserved]

Subpart E--Solid Minerals, General [Reserved]

Subpart F--[Reserved]

Subpart G--Other Solid Minerals [Reserved]

Subpart H--Geothermal Resources [Reserved]

Subpart I--OCS Sulfur [Reserved]

PART 219--[RESERVED]

Subchapter B--Offshore

PART 250--OIL AND GAS AND SULPHUR OPERATIONS IN THE OUTER 
CONTINENTAL SHELF

Subpart A--General

Authority and Definition of Terms

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

Performance Standards

250.106 What standards will the Director use to regulate lease 
operations?
250.107 What must I do to protect health, safety, property, and the 
environment?
250.108 What requirements must I follow for cranes and other 
material-handling equipment?
250.109 What documents must I prepare and maintain related to 
welding?
250.110 What must I include in my welding plan?
250.111 Who oversees operations under my welding plan?
250.112 What standards must my welding equipment meet?
250.113 What procedures must I follow when welding?
250.114 How must I install and operate electrical equipment?
250.115-250.117 [Reserved]
250.118 Will BSEE approve gas injection?
250.119 [Reserved]
250.120 How does injecting, storing, or treating gas affect my 
royalty payments?
250.121 What happens when the reservoir contains both original gas 
in place and injected gas?
250.122 What effect does subsurface storage have on the lease term?
250.123 [Reserved]
250.124 Will BSEE approve gas injection into the cap rock containing 
a sulphur deposit?

Fees

250.125 Service fees.
250.126 Electronic payment instructions.

Inspection of Operations

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

Disqualification

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

Special Types of Approvals

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

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

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

Suspensions

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

Primary Lease Requirements, Lease Term Extensions, and Lease 
Cancellations

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

Information and Reporting Requirements

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

References

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

Subpart B--Plans and Information

General Information

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

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

250.282 Do I have to conduct post-approval monitoring?

Deepwater Operations Plans (DWOP)

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

[[Page 64488]]

250.301 Inspection of 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?
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 (APM) 
or an End of Operations Report to BSEE?
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 [Reserved]
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 [Reserved]
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.
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?

[[Page 64489]]

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 BSEE requirements for assessment of fixed 
platforms?
250.921 How do I analyze my platform for cumulative fatigue?
Subpart J--Pipelines and Pipeline Rights-of-Way
250.1000 General requirements.
250.1001 Definitions.
250.1002 Design requirements for DOI pipelines.
250.1003 Installation, testing, and repair requirements for DOI 
pipelines.
250.1004 Safety equipment requirements for DOI pipelines.
250.1005 Inspection requirements for DOI pipelines.
250.1006 How must I decommission and take out of service a DOI 
pipeline?
250.1007 What to include in applications.
250.1008 Reports.
250.1009 Requirements to obtain pipeline right-of-way grants.
250.1010 General requirements for pipeline right-of-way holders.
250.1011 [Reserved]
250.1012 Required payments for pipeline right-of-way holders.
250.1013 Grounds for forfeiture of pipeline right-of-way grants.
250.1014 When pipeline right-of-way grants expire.
250.1015 Applications for pipeline right-of-way grants.
250.1016 Granting pipeline rights-of-way.
250.1017 Requirements for construction under pipeline right-of-way 
grants.
250.1018 Assignment of pipeline right-of-way grants.
250.1019 Relinquishment of pipeline right-of-way grants.
Subpart K--Oil and Gas Production Requirements

General

250.1150 What are the general reservoir production requirements?

Well Tests and Surveys

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

Classifying Reservoirs

250.1154 [Reserved]
250.1155 [Reserved]

Approvals Prior to Production

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

Production Rates

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

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 BSEE require unitization?
Subpart N--Outer Continental Shelf Civil Penalties

Outer Continental Shelf Lands Act Civil Penalties

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

Federal Oil and Gas Royalty Management Act Civil Penalties Definitions

250.1450 What definitions apply to this subpart?

Penalties After a Period To Correct

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

[[Page 64490]]

250.1456 May I request a hearing on the record regarding the amount 
of a civil penalty if I did not request a hearing on the Notice of 
Noncompliance?

Penalties Without a Period To Correct

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

General Provisions

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

Criminal Penalties

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

Bonding Requirements

250.1490 What standards must my BOEM-specified surety instrument 
meet?
250.1491 How will BOEM 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 BOEM determine if I am financially solvent?
250.1497 When will BOEM 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 BSEE measure training results?
250.1508 What must I do when BSEE administers written or oral tests?
250.1509 What must I do when BSEE administers or requires hands-on, 
simulator, or other types of testing?
250.1510 What will BSEE do if my training program does not comply 
with this subpart?
Subpart P--Sulphur Operations
250.1600 Performance standard.
250.1601 Definitions.
250.1602 Applicability.
250.1603 Determination of sulphur deposit.
250.1604 General requirements.
250.1605 Drilling requirements.
250.1606 Control of wells.
250.1607 Field rules.
250.1608 Well casing and cementing.
250.1609 Pressure testing of casing.
250.1610 Blowout preventer systems and system components.
250.1611 Blowout preventer systems tests, actuations, inspections, 
and maintenance.
250.1612 Well-control drills.
250.1613 Diverter systems.
250.1614 Mud program.
250.1615 Securing of wells.
250.1616 Supervision, surveillance, and training.
250.1617 Application for permit to drill.
250.1618 Application for permit to modify.
250.1619 Well records.
250.1620 Well-completion and well-workover requirements.
250.1621 Crew instructions.
250.1622 Approvals and reporting of well-completion and well-
workover operations.
250.1623 Well-control fluids, equipment, and operations.
250.1624 Blowout prevention equipment.
250.1625 Blowout preventer system testing, records, and drills.
250.1626 Tubing and wellhead equipment.
250.1627 Production requirements.
250.1628 Design, installation, and operation of production systems.
250.1629 Additional production and fuel gas system requirements.
250.1630 Safety-system testing and records.
250.1631 Safety device training.
250.1632 Production rates.
250.1633 Production measurement.
250.1634 Site security.
Subpart Q--Decommissioning Activities

General

250.1700 What do the terms ``decommissioning'', ``obstructions'', 
and ``facility'' mean?
250.1701 Who must meet the decommissioning obligations in this 
subpart?
250.1702 When do I accrue decommissioning obligations?
250.1703 What are the general requirements for decommissioning?
250.1704 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 BSEE order me to permanently plug a well?
250.1712 What information must I submit before I permanently plug a 
well or zone?
250.1713 Must I notify BSEE before I begin well plugging operations?
250.1714 What must I accomplish with well plugs?
250.1715 How must I permanently plug a well?
250.1716 To what depth must I remove wellheads and casings?
250.1717 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 BSEE approve partial structure removal or 
toppling in place?
250.1731 Who is responsible for decommissioning an OCS facility 
subject to an Alternate Use RUE?

Site Clearance for Wells, Platforms, and Other Facilities

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

Pipeline Decommissioning

250.1750 When may I decommission a pipeline in place?
250.1751 How do I decommission a pipeline in place?
250.1752 How do I remove a pipeline?
250.1753 After I decommission a pipeline, what information must I 
submit?
250.1754 When must I remove a pipeline decommissioned in place?
Subpart R--[Reserved]
Subpart S--Safety and Environmental Management Systems (SEMS)
250.1900 Must I have a SEMS program?
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.

[[Page 64491]]

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 BSEE determine if my SEMS program is effective?
250.1925 May BSEE 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 BSEE finds shortcomings in my SEMS program?
250.1928 What are my recordkeeping and documentation requirements?
250.1929 What are my responsibilities for submitting OCS performance 
measure data?

    Authority: 30 U.S.C. 1751; 31 U.S.C. 9701; 43 U.S.C. 1334.

Subpart A--General

Authority and Definition of Terms


Sec.  250.101  Authority and applicability.

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


Sec.  250.102  What does this part do?

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

       Table--Where To Find Information for Conducting Operations
------------------------------------------------------------------------
        For information about . . .                Refer to . . .
------------------------------------------------------------------------
(1) Applications for permit to drill,       30 CFR 250, subpart D.
(2) Development and Production Plans        30 CFR 550, subpart B.
 (DPP),
(3) Downhole commingling,                   30 CFR 250, subpart K.
(4) Exploration Plans (EP),                 30 CFR, 550, subpart B.
(5) Flaring,                                30 CFR 250, subpart K.
(6) Gas measurement,                        30 CFR 250, subpart L.
(7) Off-lease geological and geophysical    30 CFR 551.
 permits,
(8) Oil spill financial responsibility      30 CFR 553.
 coverage,
(9) Oil and gas production safety systems,  30 CFR 250, subpart H.
(10) Oil spill response plans,              30 CFR 254.
(11) Oil and gas well-completion            30 CFR 250, subpart E.
 operations,
(12) Oil and gas well-workover operations,  30 CFR 250, subpart F.
(13) Decommissioning Activities,            30 CFR 250, subpart Q.
(14) Platforms and structures,              30 CFR 250, subpart I.
(15) Pipelines and Pipeline Rights-of-Way,  30 CFR 250, subpart J and 30
                                             CFR 550, subpart J.
(16) Sulphur operations,                    30 CFR 250, subpart P.
(17) Training,                              30 CFR 250, subpart O.
(18) Unitization,                           30 CFR 250, subpart M.
------------------------------------------------------------------------

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

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


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

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


Sec.  250.105  Definitions.

    Terms used in this part will have the meanings given in the Act and 
as defined in this section:
    Act means the OCS Lands Act, as amended (43 U.S.C. 1331 et seq.).
    Affected State means with respect to any program, plan, lease sale, 
or other activity proposed, conducted, or approved under the provisions 
of the Act, any State:
    (1) The laws of which are declared, under section 4(a)(2) of the 
Act, to be the law of the United States for the portion of the OCS on 
which such activity is, or is proposed to be, conducted;
    (2) Which is, or is proposed to be, directly connected by 
transportation

[[Page 64492]]

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 mean those activities on your lease or unit 
that you:
    (1) Conduct to obtain data and information to ensure proper 
exploration or development of your lease or unit; and
    (2) Can conduct without Bureau of Ocean Energy Management (BOEM) 
approval of an application or permit.
    Archaeological interest means capable of providing scientific or 
humanistic understanding of past human behavior, cultural adaptation, 
and related topics through the application of scientific or scholarly 
techniques, such as controlled observation, contextual measurement, 
controlled collection, analysis, interpretation, and explanation.
    Archaeological resource means any material remains of human life or 
activities that are at least 50 years of age and that are of 
archaeological interest.
    Attainment area means, for any air pollutant, an area that is shown 
by monitored data or that is calculated by air quality modeling (or 
other methods determined by the Administrator of EPA to be reliable) 
not to exceed any primary or secondary ambient air quality standards 
established by EPA.
    Best available and safest technology (BAST) means the best 
available and safest technologies that the BSEE Director determines to 
be economically feasible wherever failure of equipment would have a 
significant effect on safety, health, or the environment.
    Best available control technology (BACT) means an emission 
limitation based on the maximum degree of reduction for each air 
pollutant subject to regulation, taking into account energy, 
environmental and economic impacts, and other costs. The Regional 
Supervisor will verify the BACT on a case-by-case basis, and it may 
include reductions achieved through the application of processes, 
systems, and techniques for the control of each air pollutant.
    Coastal environment means the physical, atmospheric, and biological 
components, conditions, and factors that interactively determine the 
productivity, state, condition, and quality of the terrestrial 
ecosystem from the shoreline inward to the boundaries of the coastal 
zone.
    Coastal zone means the coastal waters (including the lands therein 
and thereunder) and the adjacent shorelands (including the waters 
therein and thereunder) strongly influenced by each other and in 
proximity to the shorelands of the several coastal States. The coastal 
zone includes islands, transition and intertidal areas, salt marshes, 
wetlands, and beaches. The coastal zone extends seaward to the outer 
limit of the U.S. territorial sea and extends inland from the 
shorelines to the extent necessary to control shorelands, the uses of 
which have a direct and significant impact on the coastal waters, and 
the inward boundaries of which may be identified by the several coastal 
States, under the authority in section 305(b)(1) of the Coastal Zone 
Management Act (CZMA) of 1972.
    Competitive reservoir means a reservoir in which there are one or 
more producible or producing well completions on each of two or more 
leases or portions of leases, with different lease operating interests, 
from which the lessees plan future production.
    Correlative rights when used with respect to lessees of adjacent 
leases, means the right of each lessee to be afforded an equal 
opportunity to explore for, develop, and produce, without waste, 
minerals from a common source.
    Data means facts and statistics, measurements, or samples that have 
not been analyzed, processed, or interpreted.
    Departures mean approvals granted by the appropriate BSEE or BOEM 
representative for operating requirements/procedures other than those 
specified in the regulations found in this part. These requirements/
procedures may be necessary to control a well; properly develop a 
lease; conserve natural resources, or protect life, property, or the 
marine, coastal, or human environment.
    Development means those activities that take place following 
discovery of minerals in paying quantities, including but not limited 
to geophysical activity, drilling, platform construction, and operation 
of all directly related onshore support facilities, and which are for 
the purpose of producing the minerals discovered.
    Development geological and geophysical (G&G) activities mean those 
G&G and related data-gathering activities on your lease or unit that 
you conduct following discovery of oil, gas, or sulphur in paying 
quantities to detect or imply the presence of oil, gas, or sulphur in 
commercial quantities.
    Director means the Director of BSEE of the U.S. Department of the 
Interior, or an official authorized to act on the Director's behalf.
    District Manager means the BSEE officer with authority and 
responsibility for operations or other designated program functions for 
a district within a BSEE Region.
    Easement means an authorization for a nonpossessory, nonexclusive 
interest in a portion of the OCS, whether leased or unleased, which 
specifies the rights of the holder to use the area embraced in the 
easement in a manner consistent with the terms and conditions of the 
granting authority.
    Eastern Gulf of Mexico means all OCS areas of the Gulf of Mexico 
the BOEM Director decides are adjacent to the State of Florida. The 
Eastern Gulf of Mexico is not the same as the Eastern Planning Area, an 
area established for OCS lease sales.
    Emission offsets mean emission reductions obtained from facilities, 
either onshore or offshore, other than the facility or facilities 
covered by the proposed Exploration Plan (EP) or Development and 
Production Plan (DPP).
    Enhanced recovery operations mean pressure maintenance operations,

[[Page 64493]]

secondary and tertiary recovery, cycling, and similar recovery 
operations that alter the natural forces in a reservoir to increase the 
ultimate recovery of oil or gas.
    Existing facility, as used in 30 CFR 550.303, means an OCS facility 
described in an Exploration Plan or a Development and Production Plan 
approved before June 2, 1980.
    Exploration means the commercial search for oil, gas, or sulphur. 
Activities classified as exploration include but are not limited to:
    (1) Geophysical and geological (G&G) surveys using magnetic, 
gravity, seismic reflection, seismic refraction, gas sniffers, coring, 
or other systems to detect or imply the presence of oil, gas, or 
sulphur; and
    (2) Any drilling conducted for the purpose of searching for 
commercial quantities of oil, gas, and sulphur, including the drilling 
of any additional well needed to delineate any reservoir to enable the 
lessee to decide whether to proceed with development and production.
    Facility means:
    (1) As used in Sec.  250.130, all installations permanently or 
temporarily attached to the seabed on the OCS (including manmade 
islands and bottom-sitting structures). They include mobile offshore 
drilling units (MODUs) or other vessels engaged in drilling or downhole 
operations, used for oil, gas or sulphur drilling, production, or 
related activities. They include all floating production systems 
(FPSs), variously described as column-stabilized-units (CSUs); floating 
production, storage and offloading facilities (FPSOs); tension-leg 
platforms (TLPs); spars, etc. They also include facilities for product 
measurement and royalty determination (e.g., lease Automatic Custody 
Transfer Units, gas meters) of OCS production on installations not on 
the OCS. Any group of OCS installations interconnected with walkways, 
or any group of installations that includes a central or primary 
installation with processing equipment and one or more satellite or 
secondary installations is a single facility. The Regional Supervisor 
may decide that the complexity of the individual installations 
justifies their classification as separate facilities.
    (2) As used in 30 CFR 550.303, means all installations or devices 
permanently or temporarily attached to the seabed. They include mobile 
offshore drilling units (MODUs), even while operating in the ``tender 
assist'' mode (i.e., with skid-off drilling units) or other vessels 
engaged in drilling or downhole operations. They are used for 
exploration, development, and production activities for oil, gas, or 
sulphur and emit or have the potential to emit any air pollutant from 
one or more sources. They include all floating production systems 
(FPSs), including column-stabilized-units (CSUs); floating production, 
storage and offloading facilities (FPSOs); tension-leg platforms 
(TLPs); spars, etc. During production, multiple installations or 
devices are a single facility if the installations or devices are at a 
single site. Any vessel used to transfer production from an offshore 
facility is part of the facility while it is physically attached to the 
facility.
    (3) As used in Sec.  250.490(b), means a vessel, a structure, or an 
artificial island used for drilling, well completion, well-workover, or 
production operations.
    (4) As used in Sec. Sec.  250.900 through 250.921, means all 
installations or devices permanently or temporarily attached to the 
seabed. They are used for exploration, development, and production 
activities for oil, gas, or sulphur and emit or have the potential to 
emit any air pollutant from one or more sources. They include all 
floating production systems (FPSs), including column-stabilized-units 
(CSUs); floating production, storage and offloading facilities (FPSOs); 
tension-leg platforms (TLPs); spars, etc. During production, multiple 
installations or devices are a single facility if the installations or 
devices are at a single site. Any vessel used to transfer production 
from an offshore facility is part of the facility while it is 
physically attached to the facility.
    Flaring means the burning of natural gas as it is released into the 
atmosphere.
    Gas reservoir means a reservoir that contains hydrocarbons 
predominantly in a gaseous (single-phase) state.
    Gas-well completion means a well completed in a gas reservoir or in 
the associated gas-cap of an oil reservoir.
    Geological and geophysical (G&G) explorations mean those G&G 
surveys on your lease or unit that use seismic reflection, seismic 
refraction, magnetic, gravity, gas sniffers, coring, or other systems 
to detect or imply the presence of oil, gas, or sulphur in commercial 
quantities.
    Governor means the Governor of a State, or the person or entity 
designated by, or under, State law to exercise the powers granted to 
such Governor under the Act.
    H2S absent means:
    (1) Drilling, logging, coring, testing, or producing operations 
have confirmed the absence of H2S in concentrations that 
could potentially result in atmospheric concentrations of 20 ppm or 
more of H2S; or
    (2) Drilling in the surrounding areas and correlation of geological 
and seismic data with equivalent stratigraphic units have confirmed an 
absence of H2S throughout the area to be drilled.
    H2S present means drilling, logging, coring, testing, or producing 
operations have confirmed the presence of H2S in 
concentrations and volumes that could potentially result in atmospheric 
concentrations of 20 ppm or more of H2S.
    H2S unknown means the designation of a zone or geologic formation 
where neither the presence nor absence of H2S has been 
confirmed.
    Human environment means the physical, social, and economic 
components, conditions, and factors that interactively determine the 
state, condition, and quality of living conditions, employment, and 
health of those affected, directly or indirectly, by activities 
occurring on the OCS.
    Interpreted geological information means geological knowledge, 
often in the form of schematic cross sections, 3-dimensional 
representations, and maps, developed by determining the geological 
significance of data and analyzed geological information.
    Interpreted geophysical information means geophysical knowledge, 
often in the form of schematic cross sections, 3-dimensional 
representations, and maps, developed by determining the geological 
significance of geophysical data and analyzed geophysical information.
    Lease means an agreement that is issued under section 8 or 
maintained under section 6 of the Act and that authorizes exploration 
for, and development and production of, minerals. The term also means 
the area covered by that authorization, whichever the context requires.
    Lease term pipelines mean those pipelines owned and operated by a 
lessee or operator that are completely contained within the boundaries 
of a single lease, unit, or contiguous (not cornering) leases of that 
lessee or operator.
    Lessee means a person who has entered into a lease with the United 
States to explore for, develop, and produce the leased minerals. The 
term lessee also includes the BOEM-approved assignee of the lease, and 
the owner or the BOEM-approved assignee of operating rights for the 
lease.
    Major Federal action means any action or proposal by the Secretary 
that is subject to the provisions of section 102(2)(C) of the National 
Environmental Policy Act of 1969, 42 U.S.C. (2)(C) (i.e.,

[[Page 64494]]

an action that will have a significant impact on the quality of the 
human environment requiring preparation of an environmental impact 
statement under section 102(2)(C) of the National Environmental Policy 
Act).
    Marine environment means the physical, atmospheric, and biological 
components, conditions, and factors that interactively determine the 
productivity, state, condition, and quality of the marine ecosystem. 
These include the waters of the high seas, the contiguous zone, 
transitional and intertidal areas, salt marshes, and wetlands within 
the coastal zone and on the OCS.
    Material remains mean physical evidence of human habitation, 
occupation, use, or activity, including the site, location, or context 
in which such evidence is situated.
    Maximum efficient rate (MER) means the maximum sustainable daily 
oil or gas withdrawal rate from a reservoir that will permit economic 
development and depletion of that reservoir without detriment to 
ultimate recovery.
    Maximum production rate (MPR) means the approved maximum daily rate 
at which oil or gas may be produced from a specified oil-well or gas-
well completion.
    Minerals include oil, gas, sulphur, geopressured-geothermal and 
associated resources, and all other minerals that are authorized by an 
Act of Congress to be produced.
    Natural resources include, without limiting the generality thereof, 
oil, gas, and all other minerals, and fish, shrimp, oysters, clams, 
crabs, lobsters, sponges, kelp, and other marine animal and plant life 
but does not include water power or the use of water for the production 
of power.
    Nonattainment area means, for any air pollutant, an area that is 
shown by monitored data or that is calculated by air quality modeling 
(or other methods determined by the Administrator of EPA to be 
reliable) to exceed any primary or secondary ambient air quality 
standard established by EPA.
    Nonsensitive reservoir means a reservoir in which ultimate recovery 
is not decreased by high reservoir production rates.
    Oil reservoir means a reservoir that contains hydrocarbons 
predominantly in a liquid (single-phase) state.
    Oil reservoir with an associated gas cap means a reservoir that 
contains hydrocarbons in both a liquid and gaseous (two-phase) state.
    Oil-well completion means a well completed in an oil reservoir or 
in the oil accumulation of an oil reservoir with an associated gas cap.
    Operating rights mean any interest held in a lease with the right 
to explore for, develop, and produce leased substances.
    Operator means the person the lessee(s) designates as having 
control or management of operations on the leased area or a portion 
thereof. An operator may be a lessee, the BSEE-approved or BOEM-
approved designated agent of the lessee(s), or the holder of operating 
rights under a BOEM-approved operating rights assignment.
    Outer Continental Shelf (OCS) means all submerged lands lying 
seaward and outside of the area of lands beneath navigable waters as 
defined in section 2 of the Submerged Lands Act (43 U.S.C. 1301) whose 
subsoil and seabed appertain to the United States and are subject to 
its jurisdiction and control.
    Person includes a natural person, an association (including 
partnerships, joint ventures, and trusts), a State, a political 
subdivision of a State, or a private, public, or municipal corporation.
    Pipelines are the piping, risers, and appurtenances installed for 
transporting oil, gas, sulphur, and produced waters.
    Processed geological or geophysical information means data 
collected under a permit or a lease that have been processed or 
reprocessed. Processing involves changing the form of data to 
facilitate interpretation. Processing operations may include, but are 
not limited to, applying corrections for known perturbing causes, 
rearranging or filtering data, and combining or transforming data 
elements. Reprocessing is the additional processing other than ordinary 
processing used in the general course of evaluation. Reprocessing 
operations may include varying identified parameters for the detailed 
study of a specific problem area.
    Production means those activities that take place after the 
successful completion of any means for the removal of minerals, 
including such removal, field operations, transfer of minerals to 
shore, operation monitoring, maintenance, and workover operations.
    Production areas are those areas where flammable petroleum gas, 
volatile liquids or sulphur are produced, processed (e.g., compressed), 
stored, transferred (e.g., pumped), or otherwise handled before 
entering the transportation process.
    Projected emissions mean emissions, either controlled or 
uncontrolled, from a source or sources.
    Prospect means a geologic feature having the potential for mineral 
deposits.
    Regional Director means the BSEE officer with responsibility and 
authority for a Region within BSEE.
    Regional Supervisor means the BSEE officer with responsibility and 
authority for operations or other designated program functions within a 
BSEE Region.
    Right-of-use means any authorization issued under 30 CFR Part 550 
to use OCS lands.
    Right-of-way pipelines are those pipelines that are contained 
within:
    (1) The boundaries of a single lease or unit, but are not owned and 
operated by a lessee or operator of that lease or unit;
    (2) The boundaries of contiguous (not cornering) leases that do not 
have a common lessee or operator;
    (3) The boundaries of contiguous (not cornering) leases that have a 
common lessee or operator but are not owned and operated by that common 
lessee or operator; or
    (4) An unleased block(s).
    Routine operations, for the purposes of subpart F, mean any of the 
following operations conducted on a well with the tree installed:
    (1) Cutting paraffin;
    (2) Removing and setting pump-through-type tubing plugs, gas-lift 
valves, and subsurface safety valves that can be removed by wireline 
operations;
    (3) Bailing sand;
    (4) Pressure surveys;
    (5) Swabbing;
    (6) Scale or corrosion treatment;
    (7) Caliper and gauge surveys;
    (8) Corrosion inhibitor treatment;
    (9) Removing or replacing subsurface pumps;
    (10) Through-tubing logging (diagnostics);
    (11) Wireline fishing;
    (12) Setting and retrieving other subsurface flow-control devices; 
and
    (13) Acid treatments.
    Sensitive reservoir means a reservoir in which the production rate 
will affect ultimate recovery.
    Significant archaeological resource means those archaeological 
resources that meet the criteria of significance for eligibility to the 
National Register of Historic Places as defined in 36 CFR 60.4, or its 
successor.
    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;

[[Page 64495]]

    (2) The inefficient, excessive, or improper use, or the unnecessary 
dissipation of reservoir energy;
    (3) The locating, spacing, drilling, equipping, operating, or 
producing of any oil, gas, or sulphur well(s) in a manner that causes 
or tends to cause a reduction in the quantity of oil, gas, or sulphur 
ultimately recoverable under prudent and proper operations or that 
causes or tends to cause unnecessary or excessive surface loss or 
destruction of oil or gas; or
    (4) The inefficient storage of oil.
    Welding means all activities connected with welding, including hot 
tapping and burning.
    Wellbay is the area on a facility within the perimeter of the 
outermost wellheads.
    Well-completion operations mean the work conducted to establish 
production from a well after the production-casing string has been set, 
cemented, and pressure-tested.
    Well-control fluid means drilling mud, completion fluid, or 
workover fluid as appropriate to the particular operation being 
conducted.
    Western Gulf of Mexico means all OCS areas of the Gulf of Mexico 
except those the BOEM Director decides are adjacent to the State of 
Florida. The Western Gulf of Mexico is not the same as the Western 
Planning Area, an area established for OCS lease sales.
    Workover operations mean the work conducted on wells after the 
initial well-completion operation for the purpose of maintaining or 
restoring the productivity of a well.
    You means a lessee, the owner or holder of operating rights, a 
designated operator or agent of the lessee(s), a pipeline right-of-way 
holder, or a State lessee granted a right-of-use and easement.

Performance Standards


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

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


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

    (a) You must protect health, safety, property, and the environment 
by:
    (1) Performing all operations in a safe and workmanlike manner; 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 BSEE 
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.


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

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


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

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


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

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


Sec.  250.111  Who oversees operations under my welding plan?

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


Sec.  250.112  What standards must my welding equipment meet?

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


Sec.  250.113  What procedures must I follow when welding?

    (a) Before you weld, you must move any equipment containing 
hydrocarbons or other flammable substances at least

[[Page 64496]]

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


Sec. Sec.  250.115-250.117  [Reserved]


Sec.  250.118  Will BSEE approve gas injection?

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


Sec.  250.119  [Reserved]


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

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


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

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


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

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


Sec.  250.123  [Reserved]


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

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

Fees


Sec.  250.125  Service fees.

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

[[Page 64497]]



------------------------------------------------------------------------
   Service--processing of the
           following:                 Fee amount        30 CFR citation
------------------------------------------------------------------------
(1) [Reserved]
(2) [Reserved]
(3) Suspension of Operations/     $1,968............  Sec.   250.171(e).
 Suspension of Production (SOO/
 SOP) Request.
(4) [Reserved]
(5) [Reserved]
(6) Deepwater Operations Plan...  $3,336............  Sec.   250.292(p).
(7) [Reserved]
(8) Application for Permit to     $1,959 for initial  Sec.   250.410(d);
 Drill (APD; Form BSEE-0123).      applications        Sec.
                                   only; no fee for    250.513(b); Sec.
                                   revisions.           250.515; Sec.
                                                       250.1605; Sec.
                                                       250.1617(a); Sec.
                                                         250.1622.
(9) Application for Permit to     $116..............  Sec.   250.460;
 Modify (APM; Form BSEE-0124).                         Sec.
                                                       250.513(b); Sec.
                                                        250.613(b);
                                                       250.1618(a); Sec.
                                                         250.1622; Sec.
                                                        250.1704(g).
(10) New Facility Production      $5,030 A component  Sec.   250.802(e).
 Safety System Application for     is a piece of
 facility with more than 125       equipment or
 components.                       ancillary system
                                   that is protected
                                   by one or more of
                                   the safety
                                   devices required
                                   by API RP 14C (as
                                   incorporated by
                                   reference in Sec.
                                     250.198);
                                   $13,238
                                   additional fee
                                   will be charged
                                   if BSEE 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   Sec.   250.802(e).
 Safety System Application for     fee of $8,313
 facility with 25-125 components.  will be charged
                                   if BSEE deems it
                                   necessary to
                                   visit a facility
                                   offshore, and
                                   $4,766 to visit a
                                   facility in a
                                   shipyard.
(12) New Facility Production      $604..............  Sec.   250.802(e).
 Safety System Application for
 facility with fewer than 25
 components.
(13) Production Safety System     $561..............  Sec.   250.802(e).
 Application--Modification with
 more than 125 components
 reviewed.
(14) Production Safety System     $201..............  Sec.   250.802(e).
 Application--Modification with
 25-125 components reviewed.
(15) Production Safety System     $85...............  Sec.   250.802(e).
 Application--Modification with
 fewer than 25 components
 reviewed.
(16) Platform Application--       $21,075...........  Sec.   250.905(l).
 Installation--Under the
 Platform Verification Program.
(17) Platform Application--       $3,018............  Sec.   250.905(l).
 Installation--Fixed Structure
 Under the Platform Approval
 Program.
(18) Platform Application--       $1,536............  Sec.   250.905(l)
 Installation--Caisson/Well
 Protector.
(19) Platform Application--       $3,601............  Sec.   250.905(l).
 Modification/Repair.
(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 (ROW)  $2,569............  Sec.
 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 Request.  $4,592............  Sec.   250.1157.
(29) Downhole Commingling         $5,357............  Sec.
 Request.                                              250.1158(a).
(30) Complex Surface Commingling  $3,760............  Sec.
 and Measurement Application.                          250.1202(a); Sec.
                                                         250.1203(b);
                                                       Sec.
                                                       250.1204(a).
(31) Simple Surface Commingling   $1,271............  Sec.
 and Measurement Application.                          250.1202(a); 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 Decommission  $1,059............  Sec.   250.1751(a)
 a Pipeline (Lease Term).                              or Sec.
                                                       250.1752(a).
(36) Application to Decommission  $2,012............  Sec.   250.1751(a)
 a Pipeline (ROW).                                     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.

[[Page 64498]]

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 
BSEE Offshore Web site at: http://www.bsee.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.

Inspections of Operations


Sec.  250.130  Why does BSEE conduct inspections?

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


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

    BSEE conducts both scheduled and unscheduled inspections.


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

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


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

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

Disqualification


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

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


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

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

Special Types of Approvals


Sec.  250.140  When will I receive an oral approval?

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

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

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

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


Sec.  250.142  How do I receive approval for departures?

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


Sec.  250.143  [Reserved]


Sec.  250.144  [Reserved]


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

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

[[Page 64499]]

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


Sec.  250.146  Who is responsible for fulfilling leasehold obligations?

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

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


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

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


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

    The operator assigns a name to the facility.


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

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


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

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


Sec.  250.154  What identification signs must I display?

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


Sec.  250.160-250.167  [Reserved]

Suspensions


Sec.  250.168  May operations or production be suspended?

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


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

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

[[Page 64500]]

    (2) A willful violation of a provision of the lease or governing 
statutes and regulations.


Sec.  250.170  How long does a suspension last?

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


Sec.  250.171  How do I request a suspension?

    You must submit your request for a suspension to the Regional 
Supervisor, and BSEE must receive the request before the end of the 
lease term (i.e., end of primary term, end of the 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.  250.1603 (SOP only), 30 
CFR 550.115, or 30 CFR 550.116;
    (d) A commitment to production (SOP only); and
    (e) The service fee listed in Sec.  250.125 of this subpart.


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

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


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

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


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

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


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

    (a) The Regional Supervisor may grant an SOO when necessary to 
allow you time to begin drilling or other operations when you are 
prevented by reasons beyond your control, such as unexpected weather, 
unavoidable accidents, or drilling rig delays.
    (b) The Regional Supervisor may grant an SOO when all of the 
following conditions are met:
    (1) The lease was issued with a primary lease term of 5 years, or 
with a primary term of 8 years with a requirement to drill within 5 
years;
    (2) Before the end of the third year of the primary term, you or 
your predecessor in interest must have acquired and interpreted 
geophysical information that indicates:
    (i) The presence of a salt sheet;
    (ii) That all or a portion of a potential hydrocarbon-bearing 
formation may lie beneath or adjacent to the salt sheet; and
    (iii) The salt sheet interferes with identification of the 
potential hydrocarbon-bearing formation.
    (3) The interpreted geophysical information required under 
paragraph (b)(2) of this section must include full 3-D depth migration 
beneath the salt sheet and over the entire lease area.
    (4) Before requesting the suspension, you have conducted or are 
conducting additional data processing or interpretation of the 
geophysical information with the objective of identifying a potential 
hydrocarbon-bearing formation.
    (5) You demonstrate that additional time is necessary to:
    (i) Complete current processing or interpretation of existing 
geophysical data or information;
    (ii) Acquire, process, or interpret new geophysical data or 
information; or
    (iii) Drill into the potential hydrocarbon-bearing formation 
identified as a result of the activities conducted in paragraphs 
(b)(2), (b)(4), and (b)(5) of this section.
    (c) The Regional Supervisor may grant an SOO to conduct additional 
geological and geophysical data analysis that may lead to the drilling 
of a well below 25,000 feet true vertical depth below the datum at mean 
sea level (TVD SS) when all of the following conditions are met:
    (1) The lease was issued with a primary lease term of:
    (i) Five years; or
    (ii) Eight years with a requirement to drill within 5 years.
    (2) Before the end of the fifth year of the primary term, you or 
your predecessor in interest must have acquired and interpreted 
geophysical information that:
    (i) Indicates that all or a portion of a potential hydrocarbon-
bearing formation lies below 25,000 feet TVD SS; and
    (ii) Includes full 3-D depth migration over the entire lease area.
    (3) Before requesting the suspension, you have conducted or are 
conducting additional data processing or interpretation of the 
geophysical information with the objective of identifying a potential 
hydrocarbon-bearing geologic structure or stratigraphic trap lying 
below 25,000 feet TVD SS.
    (4) You demonstrate that additional time is necessary to:
    (i) Complete current processing or interpretation of existing 
geophysical data or information;
    (ii) Acquire, process, or interpret new geophysical or geological 
data or

[[Page 64501]]

information that would affect the decision to drill the same geologic 
structure or stratigraphic trap, as determined by the Regional 
Supervisor, identified in paragraphs (c)(2) and (c)(3) of this section; 
or
    (iii) Drill a well below 25,000 feet TVD SS into the geologic 
structure or stratigraphic trap identified as a result of the 
activities conducted in paragraphs (c)(2), (c)(3), and (c)(4)(i) and 
(ii) of this section.


Sec.  250.176  Does a suspension affect my royalty payment?

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


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

    If BSEE grants or directs a suspension under paragraph Sec.  
250.172(b), the Regional Supervisor may require you to:
    (a) Conduct a site-specific study.
    (1) The Regional Supervisor must approve or prescribe the scope for 
any site-specific study that you perform.
    (2) The study must evaluate the cause of the hazard, the potential 
damage, and the available mitigation measures.
    (3) You must pay for the study unless you request, and the Regional 
Supervisor agrees to arrange, payment by another party.
    (4) You must furnish copies and results of the study to the 
Regional Supervisor.
    (5) BSEE will make the results available to other interested 
parties and to the public.
    (6) The Regional Supervisor will use the results of the study and 
any other information that becomes available:
    (i) To decide if the suspension can be lifted; and
    (ii) To determine any actions that you must take to mitigate or 
avoid any damage to the environment, life, or property.
    (b) Submit a revised Exploration Plan (including any required 
mitigating measures);
    (c) Submit a revised Development and Production Plan (including any 
required mitigating measures); or
    (d) Submit a revised Development Operations Coordination Document 
according to 30 CFR part 550, subpart B.

Primary Lease Requirements, Lease Term Extensions, and Lease 
Cancellations


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

    (a) If your lease is in its primary term:
    (1) You must submit a report to the District Manager according to 
paragraphs (h) and (i) of this section whenever production begins 
initially, whenever production ceases during the last 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 556). For 
purposes of this section, the term operations means, drilling, well-
reworking, or production in paying quantities. The objective of the 
drilling or well-reworking must be to establish production in paying 
quantities on the lease.
    (b) If you stop conducting operations during the last 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 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. Sec.  250.181-250.185  [Reserved]

Information and Reporting Requirements


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

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

[[Page 64502]]

or otherwise exempt from public disclosure under law or regulation.


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

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


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

    (a) You must report the following incidents to the District Manager 
immediately via oral communication, and provide a written follow-up 
report (hard copy or electronically transmitted) within 15 calendar 
days after the incident:
    (1) All fatalities.
    (2) All injuries that require the evacuation of the injured 
person(s) from the facility to shore or to another offshore facility.
    (3) All losses of well control. ``Loss of well control'' means:
    (i) Uncontrolled flow of formation or other fluids. The flow may be 
to an exposed formation (an underground blowout) or at the surface (a 
surface blowout);
    (ii) Flow through a diverter; or
    (iii) Uncontrolled flow resulting from a failure of surface 
equipment or procedures.
    (4) All fires and explosions.
    (5) All reportable releases of hydrogen sulfide (H2S) 
gas, as defined in Sec.  250.490(l).
    (6) All collisions that result in property or equipment damage 
greater than $25,000. ``Collision'' means the act of a moving vessel 
(including an aircraft) striking another vessel, or striking a 
stationary vessel or object (e.g., a boat striking a drilling rig or 
platform). ``Property or equipment damage'' means the cost of labor and 
material to restore all affected items to their condition before the 
damage, including, but not limited to, the OCS facility, a vessel, 
helicopter, or equipment. It does not include the cost of salvage, 
cleaning, gas-freeing, dry docking, or demurrage.
    (7) All incidents involving structural damage to an OCS facility. 
``Structural damage'' means damage severe enough so that operations on 
the facility cannot continue until repairs are made.
    (8) All incidents involving crane or personnel/material handling 
operations.
    (9) All incidents that damage or disable safety systems or 
equipment (including firefighting systems).
    (b) You must provide a written report of the following incidents to 
the District Manager within 15 calendar days after the incident:
    (1) Any injuries that result in one or more days away from work or 
one or more days on restricted work or job transfer. One or more days 
means the injured person was not able to return to work or to all of 
their normal duties the day after the injury occurred;
    (2) All gas releases that initiate equipment or process shutdown;
    (3) All incidents that require operations personnel on the facility 
to muster for evacuation for reasons not related to weather or drills;
    (4) All other incidents, not listed in paragraph (a) of this 
section, resulting in property or equipment damage greater than 
$25,000.


Sec.  250.189  Reporting requirements for incidents requiring immediate 
notification.

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


Sec.  250.190  Reporting requirements for incidents requiring written 
notification.

    (a) For any incident covered under Sec.  250.188, you must submit a 
written report within 15 calendar days after the incident to the 
District Manager. The report must contain the following information:
    (1) Date and time of occurrence;
    (2) Operator, and operator representative's name and telephone 
number;
    (3) Contractor, and contractor representative's name and telephone 
number (if a contractor is involved in the incident or injury);
    (4) Lease number, OCS area, and block;
    (5) Platform/facility name and number, or pipeline segment number;
    (6) Type of incident or injury;
    (7) Operation or activity at time of incident (i.e., drilling, 
production, workover, completion, pipeline, crane etc.);
    (8) Description of incident, damage, or injury (including days away 
from work, restricted work or job transfer), and any corrective action 
taken; and
    (9) Property or equipment damage estimate (in U.S. dollars).
    (b) You may submit a report or form prepared for another agency in 
lieu of the written report required by paragraph (a) of this section, 
provided the report or form contains all required information.
    (c) The District Manager may require you to submit additional 
information about an incident on a case-by-case basis.


Sec.  250.191  How does BSEE conduct incident investigations?

    Any investigation that BSEE conducts under the authority of 
sections 22(d)(1) and (2) of the Act (43 U.S.C. 1348(d)(1) and (2)) is 
a fact-finding proceeding with no adverse parties. The purpose of the 
investigation is to prepare a public report that determines the cause 
or causes of the incident. The investigation may involve panel meetings 
conducted by a chairperson appointed by BSEE. The following 
requirements apply to any panel meetings involving persons giving 
testimony:
    (a) A person giving testimony may have legal or other 
representative(s) present to provide advice or counsel while the person 
is giving testimony. The chairperson may require a verbatim transcript 
to be made of all oral testimony. The chairperson also may accept a 
sworn written statement in lieu of oral testimony.
    (b) Only panel members, and any experts the panel deems necessary, 
may address questions to any person giving testimony.
    (c) The chairperson may issue subpoenas to persons to appear and 
provide testimony or documents at a

[[Page 64503]]

panel meeting. A subpoena may not require a person to attend a panel 
meeting held at a location more than 100 miles from where a subpoena is 
served.
    (d) Any person giving testimony may request compensation for 
mileage, and fees for services, within 90 days after the panel meeting. 
The compensated expenses must be similar to mileage and fees the U.S. 
District Courts allow.


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

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


Sec.  250.193  Reports and investigations of apparent violations.

    Any person may report to BSEE 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 BSEE receives a report 
of an apparent violation, or when a BSEE employee detects an apparent 
violation after making an initial determination of the validity, BSEE 
will investigate according to BSEE procedures.


Sec.  250.194  How must I protect archaeological resources?

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


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

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


Sec.  250.196  Reimbursements for reproduction and processing costs.

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


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

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

[[Page 64504]]



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

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

------------------------------------------------------------------------
                                                             Special
     If . . .      BSEE will release   At this time . .   provisions . .
                         . . .                .                 .
------------------------------------------------------------------------
(1) The Director   Geophysical data,  At any time,       BSEE will
 determines that    Geological data                       release data
 data and           Interpreted G&G                       and
 information are    information,                          information
 needed for         Processed G&G                         only if
 specific           information,                          release would
 scientific or      Analyzed                              further the
 research           geological                            National
 purposes for the   information,                          interest
 Government,                                              without unduly
                                                          damaging the
                                                          competitive
                                                          position of
                                                          the lessee.
(2) Data or        Geophysical data,  60 days after      BSEE will
 information is     Geological data,   BSEE receives      release the
 collected with     Interpreted G&G    the data or        data and
 high-resolution    information,       information, if    information
 systems (e.g.,     Processed          the Regional       earlier than
 bathymetry, side-  geological         Supervisor deems   60 days if the
 scan sonar,        information,       it necessary,      Regional
 subbottom          Analyzed                              Supervisor
 profiler, and      geological                            determines it
 magnetometer) to   information,                          is needed by
 comply with                                              affected
 safety or                                                States to make
 environmental                                            decisions
 protection                                               under 30 CFR
 requirements,                                            550, subpart
                                                          B. The
                                                          Regional
                                                          Supervisor
                                                          will
                                                          reconsider
                                                          earlier
                                                          release if you
                                                          satisfy him/
                                                          her that it
                                                          would unduly
                                                          damage your
                                                          competitive
                                                          position.
(3) Your lease is  Geophysical data,  When your lease    This release
 no longer in       Geological data,   terminates,        time applies
 effect,            Processed G&G                         only if the
                    information                           provisions in
                    Interpreted G&G                       this table
                    information,                          governing high-
                    Analyzed                              resolution
                    geological                            systems and
                    information,                          the provisions
                                                          in 30 CFR
                                                          552.7 do not
                                                          apply. The
                                                          release time
                                                          applies to the
                                                          geophysical
                                                          data and
                                                          information
                                                          only if
                                                          acquired
                                                          postlease for
                                                          a lessee's
                                                          exclusive use.

[[Page 64505]]

 
(4) Your lease is  Geophysical data,  10 years after     This release
 still in effect,   Processed          you submit the     time applies
                    geophysical        data and           only if the
                    information,       information,       provisions in
                    Interpreted G&G                       this table
                    information,                          governing high-
                                                          resolution
                                                          systems and
                                                          the provisions
                                                          in 30 CFR
                                                          552.7 do not
                                                          apply. This
                                                          release time
                                                          applies to the
                                                          geophysical
                                                          data and
                                                          information
                                                          only if
                                                          acquired
                                                          postlease for
                                                          a lessee's
                                                          exclusive use.
(5) Your lease is  Geological data,   2 years after the  These release
 still in effect    Analyzed           required           times apply
 and within the     geological         submittal date     only if the
 primary term       information,       or 60 days after   provisions in
 specified in the                      a lease sale if    this table
 lease,                                any portion of     governing high-
                                       an offered lease   resolution
                                       is within 50       systems and
                                       miles of a well,   the provisions
                                       whichever is       in 30 CFR
                                       later,             552.7 do not
                                                          apply. If the
                                                          primary term
                                                          specified in
                                                          the lease is
                                                          extended under
                                                          the heading of
                                                          ``Suspensions'
                                                          ' in this
                                                          subpart, the
                                                          extension
                                                          applies to
                                                          this
                                                          provision.
(6) Your lease is  Geological data,   2 years after the  None.
 in effect and      Analyzed           required
 beyond the         geological         submittal date,
 primary term       information,
 specified in the
 lease,
(7) Data or        Descriptions of    When the well      Directional
 information is     downhole           goes on            survey data
 submitted on       locations,         production or      may be
 well operations,   operations, and    when geological    released
                    equipment,         data is released   earlier to the
                                       according to       owner of an
                                       Sec.  Sec.         adjacent lease
                                       250.197(b)(5)      according to
                                       and (b)(6),        Subpart D of
                                       whichever occurs   this part.
                                       earlier,
(8) Data and       Any data or        At any time,       None.
 information are    information
 obtained from      obtained,
 beneath unleased
 land as a result
 of a well
 deviation that
 has not been
 approved by the
 District Manager
 or Regional
 Supervisor,
(9) Except for     G&G data,          Geological data    None.
 high-resolution    analyzed           and information:
 data and           geological         10 years after
 information        information,       BOEM issues the
 released under     processed and      permit;
 paragraph (b)(2)   interpreted G&G    Geophysical
 of this section    information,       data: 50 years
 data and                              after BOEM
 information                           issues the
 acquired by a                         permit;
 permit under 30                       Geophysical
 CFR part 551 are                      information: 25
 submitted by a                        years after BOEM
 lessee under 30                       issues the
 CFR part 203, 30                      permit,
 CFR part 250, or
 30 CFR part 550,
------------------------------------------------------------------------

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

References


Sec.  250.198  Documents incorporated by reference.

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

[[Page 64506]]

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 BSEE official.
    (d) You may inspect these documents at the Bureau of Safety and 
Environmental Enforcement, 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.htm.
    (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), incorporated by reference at Sec.  250.901.
    (2) ACI 318R-95, Commentary on Building Code Requirements for 
Reinforced Concrete, incorporated by reference at Sec.  250.901.
    (3) ACI 357R-84, Guide for the Design and Construction of Fixed 
Offshore Concrete Structures, 1984; reapproved 1997, incorporated by 
reference at Sec.  250.901.
    (f) American Institute of Steel Construction, Inc. (AISC), AISC 
Standards, One East Wacker Drive, Suite 700, Chicago, IL 60601-1802; 
http://www.aisc.org; phone: 312-670-2400:
    (1) ANSI/AISC 360-05, Specification for Structural Steel Buildings 
incorporated by reference at Sec.  250.901.
    (2) [Reserved]
    (g) American National Standards Institute (ANSI), ANSI/ASME Codes, 
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 and Sec.  250.1629;
    (2) ANSI/ASME Boiler and Pressure Vessel Code, Section IV, Rules 
for Construction of Heating Boilers; including Appendices 1, 2, 3, 5, 
6, and Non-mandatory Appendices B, C, D, E, F, H, I, K, L, and M, and 
the Guide to Manufacturers Data Report Forms, 2004 Edition; July 1, 
2005 Addenda, and all Section IV Interpretations Volume 55, 
incorporated by reference at Sec. Sec.  250.803 and 250.1629;
    (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. Sec.  250.803 and 250.1629;
    (4) ANSI/ASME B 16.5-2003, Pipe Flanges and Flanged Fittings 
incorporated by reference at Sec.  250.1002;
    (5) ANSI/ASME B 31.8-2003, Gas Transmission and Distribution Piping 
Systems incorporated by reference at Sec.  250.1002;
    (6) ANSI/ASME SPPE-1-1994, Quality Assurance and Certification of 
Safety and Pollution Prevention Equipment Used in Offshore Oil and Gas 
Operations, incorporated by reference at Sec.  250.806;
    (7) ANSI/ASME 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;
    (8) ANSI Z88.2-1992, American National Standard for Respiratory 
Protection, incorporated by reference at, Sec.  250.490.
    (h) American Petroleum Institute (API), API Recommended Practices 
(RP), Specs, Standards, Manual of Petroleum Measurement Standards 
(MPMS) chapters, 1220 L Street, NW., Washington, DC 20005-4070; http://www.api.org; phone: 202-682-8000:
    (1) API 510, Pressure Vessel Inspection Code: In-Service 
Inspection, Rating, Repair, and Alteration, Downstream Segment, Ninth 
Edition, June 2006; incorporated by reference at Sec. Sec.  250.803 and 
250.1629;
    (2) API Bulletin 2INT-DG, Interim Guidance for Design of Offshore 
Structures for Hurricane Conditions, May 2007; incorporated by 
reference at Sec.  250.901;
    (3) API Bulletin 2INT-EX, Interim Guidance for Assessment of 
Existing Offshore Structures for Hurricane Conditions, May 2007; 
incorporated by reference at Sec.  250.901;
    (4) API Bulletin 2INT-MET, Interim Guidance on Hurricane Conditions 
in the Gulf of Mexico, May 2007; incorporated by reference at Sec.  
250.901;
    (5) API MPMS, Chapter 1--Vocabulary, Second Edition, July 1994; 
incorporated by reference at Sec.  250.1201;
    (6) API MPMS, Chapter 2--Tank Calibration, Section 2A--Measurement 
and Calibration of Upright Cylindrical Tanks by the Manual Tank 
Strapping Method, First Edition, February 1995; reaffirmed February 
2007; incorporated by reference at Sec.  250.1202;
    (7) API MPMS, Chapter 2--Tank Calibration, Section 2B--Calibration 
of Upright Cylindrical Tanks Using the Optical Reference Line Method, 
First Edition, March 1989; reaffirmed, December 2007; incorporated by 
reference at Sec.  250.1202;
    (8) API MPMS, Chapter 3--Tank Gauging, Section 1A--Standard 
Practice for the Manual Gauging of Petroleum and Petroleum Products, 
Second Edition, August 2005; incorporated by reference at Sec.  
250.1202;
    (9) API MPMS, Chapter 3--Tank Gauging, Section 1B--Standard 
Practice for Level Measurement of Liquid Hydrocarbons in Stationary 
Tanks by Automatic Tank Gauging, Second Edition, June 2001, reaffirmed, 
October 2006; incorporated by reference at Sec.  250.1202;
    (10) API MPMS, Chapter 4--Proving Systems, Section 1--Introduction, 
Third Edition, February 2005; incorporated by reference at Sec.  
250.1202;
    (11) API MPMS, Chapter 4--Proving Systems, Section 2--Displacement 
Provers, Third Edition, September 2003; incorporated by reference at 
Sec.  250.1202;
    (12) API MPMS, Chapter 4--Proving Systems, Section 4--Tank Provers, 
Second Edition, May 1998, reaffirmed November 2005; incorporated by 
reference at Sec.  250.1202;
    (13) API MPMS, Chapter 4--Proving Systems, Section 5--Master-Meter 
Provers, Second Edition, May 2000, reaffirmed: August 2005; 
incorporated by reference at Sec.  250.1202;
    (14) API MPMS, Chapter 4--Proving Systems, Section 6--Pulse 
Interpolation, Second Edition, May 1999; reaffirmed 2003; incorporated 
by reference at Sec.  250.1202;
    (15) API MPMS, Chapter 4--Proving Systems, Section 7--Field 
Standard Test Measures, Second Edition, December 1998; reaffirmed 2003; 
incorporated by reference at Sec.  250.1202;

[[Page 64507]]

    (16) API MPMS, Chapter 5--Metering, Section 1--General 
Considerations for Measurement by Meters, Fourth Edition, September 
2005; incorporated by reference at Sec.  250.1202;
    (17) API MPMS, Chapter 5--Metering, Section 2--Measurement of 
Liquid Hydrocarbons by Displacement Meters, Third Edition, September 
2005; incorporated by reference at Sec.  250.1202;
    (18) API MPMS Chapter 5--Metering, Section 3--Measurement of Liquid 
Hydrocarbons by Turbine Meters, Fifth Edition, September 2005; 
incorporated by reference at Sec.  250.1202;
    (19) API MPMS, Chapter 5--Metering, Section 4--Accessory Equipment 
for Liquid Meters, Fourth Edition, September 2005; incorporated by 
reference at Sec.  250.1202;
    (20) API MPMS, Chapter 5--Metering, Section 5--Fidelity and 
Security of Flow Measurement Pulsed-Data Transmission Systems, Second 
Edition, August 2005; incorporated by reference at Sec.  250.1202;
    (21) API MPMS, Chapter 6--Metering Assemblies, Section 1--Lease 
Automatic Custody Transfer (LACT) Systems, Second Edition, May 1991; 
reaffirmed, April 2007; incorporated by reference at Sec.  250.1202;
    (22) API MPMS, Chapter 6--Metering Assemblies, Section 6--Pipeline 
Metering Systems, Second Edition, May 1991; reaffirmed, February 2007; 
incorporated by reference at Sec.  250.1202;
    (23) API MPMS, Chapter 6--Metering Assemblies, Section 7--Metering 
Viscous Hydrocarbons, Second Edition, May 1991; reaffirmed, April 2007; 
incorporated by reference at Sec.  250.1202;
    (24) API MPMS, Chapter 7--Temperature Determination, First Edition, 
June 2001; reaffirmed, March 2007; incorporated by reference at Sec.  
250.1202;
    (25) API MPMS, Chapter 8--Sampling, Section 1--Standard Practice 
for Manual Sampling of Petroleum and Petroleum Products, Third Edition, 
October 1995; reaffirmed, March 2006; incorporated by reference at 
Sec.  250.1202;
    (26) API MPMS, Chapter 8--Sampling, Section 2--Standard Practice 
for Automatic Sampling of Liquid Petroleum and Petroleum Products, 
Second Edition, October 1995; reaffirmed, June 2005; incorporated by 
reference at Sec.  250.1202;
    (27) API MPMS, Chapter 9--Density Determination, Section 1--
Standard Test Method for Density, Relative Density (Specific Gravity), 
or API Gravity of Crude Petroleum and Liquid Petroleum Products by 
Hydrometer Method, Second Edition, December 2002; reaffirmed October 
2005; incorporated by reference at Sec.  250.1202(a)(3) and (l)(4);
    (28) API MPMS, Chapter 9--Density Determination, Section 2--
Standard Test Method for Density or Relative Density of Light 
Hydrocarbons by Pressure Hydrometer, Second Edition, March 2003; 
incorporated by reference at Sec.  250.1202;
    (29) API MPMS, Chapter 10--Sediment and Water, Section 1--Standard 
Test Method for Sediment in Crude Oils and Fuel Oils by the Extraction 
Method, Third Edition, November 2007; incorporated by reference at 
Sec.  250.1202;
    (30) API MPMS, Chapter 10--Sediment and Water, Section 2--Standard 
Test Method for Water in Crude Oil by Distillation, Second Edition, 
November 2007; incorporated by reference at Sec.  250.1202;
    (31) API MPMS, Chapter 10--Sediment and Water, Section 3--Standard 
Test Method for Water and Sediment in Crude Oil by the Centrifuge 
Method (Laboratory Procedure), Third Edition, May 2008; incorporated by 
reference at Sec.  250.1202;
    (32) API MPMS, Chapter 10--Sediment and Water, Section 4--
Determination of Water and/or Sediment in Crude Oil by the Centrifuge 
Method (Field Procedure), Third Edition, December 1999; incorporated by 
reference at Sec.  250.1202;
    (33) API MPMS, Chapter 10--Sediment and Water, Section 9--Standard 
Test Method for Water in Crude Oils by Coulometric Karl Fischer 
Titration, Second Edition, December 2002; reaffirmed 2005; incorporated 
by reference at Sec.  250.1202;
    (34) API MPMS, Chapter 11.1--Volume Correction Factors, Volume 1, 
Table 5A--Generalized Crude Oils and JP-4 Correction of Observed API 
Gravity to API Gravity at 60 [deg]F, and Table 6A--Generalized Crude 
Oils and JP-4 Correction of Volume to 60 [deg]F Against API Gravity at 
60 [deg]F, API Standard 2540, First Edition, August 1980; reaffirmed 
March 1997; incorporated by reference at Sec.  250.1202;
    (35) API MPMS, Chapter 11.2.2--Compressibility Factors for 
Hydrocarbons: 0.350-0.637 Relative Density (60 [deg]F/60 [deg]F) and -
50 [deg]F to 140 [deg]F Metering Temperature, Second Edition, October 
1986; reaffirmed: December 2007; incorporated by reference at Sec.  
250.1202;
    (36) API MPMS, Chapter 11--Physical Properties Data, Addendum to 
Section 2, Part 2--Compressibility Factors for Hydrocarbons, 
Correlation of Vapor Pressure for Commercial Natural Gas Liquids, First 
Edition, December 1994; reaffirmed, December 2002; incorporated by 
reference at Sec.  250.1202;
    (37) API MPMS, Chapter 12--Calculation of Petroleum Quantities, 
Section 2--Calculation of Petroleum Quantities Using Dynamic 
Measurement Methods and Volumetric Correction Factors, Part 1--
Introduction, Second Edition, May 1995; reaffirmed March 2002; 
incorporated by reference at Sec.  250.1202;
    (38) API MPMS, Chapter 12--Calculation of Petroleum Quantities, 
Section 2--Calculation of Petroleum Quantities Using Dynamic 
Measurement Methods and Volumetric Correction Factors, Part 2--
Measurement Tickets, Third Edition, June 2003; incorporated by 
reference at Sec.  250.1202;
    (39) API MPMS, Chapter 14--Natural Gas Fluids Measurement, Section 
3--Concentric, Square-Edged Orifice Meters, Part 1--General Equations 
and Uncertainty Guidelines, Third Edition, September 1990; reaffirmed 
January 2003; incorporated by reference at Sec.  250.1203;
    (40) API MPMS, Chapter 14--Natural Gas Fluids Measurement, Section 
3--Concentric, Square-Edged Orifice Meters, Part 2--Specification and 
Installation Requirements, Fourth Edition, April 2000; reaffirmed March 
2006; incorporated by reference at Sec.  250.1203;
    (41) API MPMS, Chapter 14--Natural Gas Fluids Measurement, Section 
3--Concentric, Square-Edged Orifice Meters; Part 3--Natural Gas 
Applications; Third Edition, August 1992; Errata March 1994, 
reaffirmed, February 2009; incorporated by reference at Sec.  250.1203;
    (42) API MPMS, Chapter 14.5/GPA Standard 2172-09; Calculation of 
Gross Heating Value, Relative Density, Compressibility and Theoretical 
Hydrocarbon Liquid Content for Natural Gas Mixtures for Custody 
Transfer; Third Edition, January 2009; incorporated by reference at 
Sec.  250.1203;
    (43) API MPMS, Chapter 14--Natural Gas Fluids Measurement, Section 
6--Continuous Density Measurement, Second Edition, April 1991; 
reaffirmed, February 2006; incorporated by reference at Sec.  250.1203;
    (44) API MPMS, Chapter 14--Natural Gas Fluids Measurement, Section 
8--Liquefied Petroleum Gas Measurement, Second Edition, July 1997; 
reaffirmed, March 2006; incorporated by reference at Sec.  250.1203;
    (45) API MPMS, Chapter 20--Section 1--Allocation Measurement, First 
Edition, September 1993; reaffirmed October 2006; incorporated by 
reference at Sec.  250.1202;

[[Page 64508]]

    (46) API MPMS, Chapter 21--Flow Measurement Using Electronic 
Metering Systems, Section 1--Electronic Gas Measurement, First Edition, 
August 1993; reaffirmed, July 2005; incorporated by reference at Sec.  
250.1203;
    (47) API RP 2A-WSD, Recommended Practice for Planning, Designing 
and Constructing Fixed Offshore Platforms--Working Stress Design, 
Twenty-first Edition, December 2000; Errata and Supplement 1, December 
2002; Errata and Supplement 2, September 2005; Errata and Supplement 3, 
October 2007; incorporated by reference at Sec. Sec.  250.901, 250.908, 
250.919, and 250.920;
    (48) API RP 2D, Operation and Maintenance of Offshore Cranes, Sixth 
Edition, May 2007; incorporated by reference at Sec.  250.108;
    (49) API RP 2FPS, RP for Planning, Designing, and Constructing 
Floating Production Systems; First Edition, March 2001; incorporated by 
reference at Sec.  250.901;
    (50) API RP 2I, In-Service Inspection of Mooring Hardware for 
Floating Structures; Third Edition, April 2008; incorporated by 
reference at Sec.  250.901(a) and (d);
    (51) API RP 2RD, Recommended Practice for Design of Risers for 
Floating Production Systems (FPSs) and Tension-Leg Platforms (TLPs), 
First Edition, June 1998; reaffirmed, May 2006, Errata, June 2009; 
incorporated by reference at Sec. Sec.  250.800; 250.901 and 250.1002;
    (52) API RP 2SK, Design and Analysis of Stationkeeping Systems for 
Floating Structures, Third Edition, October 2005, Addendum, May 2008; 
incorporated by reference at Sec. Sec.  250.800 and 250.901;
    (53) API RP 2SM, Recommended Practice for Design, Manufacture, 
Installation, and Maintenance of Synthetic Fiber Ropes for Offshore 
Mooring, First Edition, March 2001, Addendum, May 2007; incorporated by 
reference at Sec.  250.901;
    (54) API RP 2T, Recommended Practice for Planning, Designing, and 
Constructing Tension Leg Platforms, Second Edition, August 1997; 
incorporated by reference at Sec.  250.901;
    (55) 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; incorporated by reference at 
Sec. Sec.  250.801 and 250.804;
    (56) API RP 14C, Recommended Practice for Analysis, Design, 
Installation, and Testing of Basic Surface Safety Systems for Offshore 
Production Platforms, Seventh Edition, March 2001, reaffirmed: March 
2007; incorporated by reference at Sec. Sec.  250.125, 250.292, 
250.802, 250.803, 250.804, 250.1002, 250.1004, 250.1628, 250.1629, and 
250.1630;
    (57) API RP 14E, Recommended Practice for Design and Installation 
of Offshore Production Platform Piping Systems, Fifth Edition, October 
1991; reaffirmed, March 2007; incorporated by reference at Sec. Sec.  
250.802 and 250.1628;
    (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; incorporated by reference at Sec. Sec.  
250.114, 250.803, and 250.1629;
    (59) API RP 14FZ, Recommended Practice for Design and Installation 
of Electrical Systems for Fixed and Floating Offshore Petroleum 
Facilities for Unclassified and Class I, Zone 0, Zone 1 and Zone 2 
Locations, First Edition, September 2001, reaffirmed: March 2007; 
incorporated by reference at Sec. Sec.  250.114, 250.803, and 250.1629;
    (60) API RP 14G, Recommended Practice for Fire Prevention and 
Control on Fixed Open-type Offshore Production Platforms, Fourth 
Edition, April 2007; incorporated by reference at Sec. Sec.  250.803 
and 250.1629;
    (61) API RP 14H, Recommended Practice for Installation, Maintenance 
and Repair of Surface Safety Valves and Underwater Safety Valves 
Offshore, Fifth Edition, August 2007; incorporated by reference at 
Sec. Sec.  250.802 and 250.804;
    (62) API RP 14J, Recommended Practice for Design and Hazards 
Analysis for Offshore Production Facilities, Second Edition, May 2001; 
reaffirmed: March 2007; incorporated by reference at Sec. Sec.  250.800 
and 250.901;
    (63) API RP 53, Recommended Practices for Blowout Prevention 
Equipment Systems for Drilling Wells, Third Edition, March 1997; 
reaffirmed September 2004; incorporated by reference at Sec. Sec.  
250.442, 250.446, 250.516, and 250.617,
    (64) API RP 65, Recommended Practice for Cementing Shallow Water 
Flow Zones in Deepwater Wells, First Edition, September 2002; 
incorporated by reference at Sec.  250.415;
    (65) API RP 500, Recommended Practice for Classification of 
Locations for Electrical Installations at Petroleum Facilities 
Classified as Class I, Division 1 and Division 2, Second Edition, 
November 1997; reaffirmed November 2002; incorporated by reference at 
Sec. Sec.  250.114, 250.459, 250.802, 250.803, 250.1628, and 250.1629;
    (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; incorporated by reference at 
Sec. Sec.  250.114, 250.459, 250.802, 250.803, 250.1628, and 250.1629;
    (67) API RP 2556, Recommended Practice for Correcting Gauge Tables 
for Incrustation, Second Edition, August 1993; reaffirmed November 
2003; incorporated by reference at Sec.  250.1202;
    (68) ANSI/API 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; incorporated by reference at Sec.  250.806;
    (69) API Spec. 2C, Specification for Offshore Pedestal Mounted 
Cranes, Sixth Edition, March 2004, Effective Date: September 2004; 
incorporated by reference at Sec.  250.108;
    (70) ANSI/API 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; incorporated by 
reference at Sec. Sec.  250.806 and 250.1002;
    (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; incorporated by reference at Sec.  250.806;
    (72) ANSI/API Spec. 6D, Specification for Pipeline Valves, Twenty-
third Edition, April 2008; Effective Date: October 1, 2008, Errata 1, 
June 2008; Errata 2, November 2008; Errata 3, February 2009; Addendum 
1, October 2009; Contains API Monogram Annex as Part of U.S. National 
Adoption; ISO 14313:2007 (Identical), Petroleum and natural gas 
industries--Pipeline transportation systems--Pipeline valves; 
incorporated by reference at Sec.  250.1002;
    (73) ANSI/API Spec. 14A, Specification for Subsurface Safety Valve 
Equipment, Eleventh Edition, October 2005, Effective Date: May 1,

[[Page 64509]]

2006; also available as ISO 10432:2004; incorporated by reference at 
Sec.  250.806;
    (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; incorporated by reference at 
Sec. Sec.  250.803, 250.1002, and 250.1007;
    (75) API Standard 2551, Measurement and Calibration of Horizontal 
Tanks, First Edition, 1965; reaffirmed March 2002; incorporated by 
reference at Sec.  250.1202;
    (76) API Standard 2552, USA Standard Method for Measurement and 
Calibration of Spheres and Spheroids, First Edition, 1966; reaffirmed, 
October 2007; incorporated by reference at Sec.  250.1202;
    (77) API Standard 2555, Method for Liquid Calibration of Tanks, 
First Edition, September 1966; reaffirmed March 2002; incorporated by 
reference at Sec.  250.1202.
    (78) API RP 90, Annular Casing Pressure Management for Offshore 
Wells, First Edition, August 2006, incorporated by reference at Sec.  
250.518.
    (79) API RP 65-Part 2, Isolating Potential Flow Zones During Well 
Construction; First Edition, May 2010; incorporated by reference at 
Sec.  250.415.
    (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; incorporated 
by reference at Sec. Sec.  250.1900, 250.1902, 250.1903, 250.1909, 
250.1920.
    (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;
    (2) ASTM Standard C 94/C 94M-07, approved January 1, 2007, Standard 
Specification for Ready-Mixed Concrete; incorporated by reference at 
Sec.  250.901;
    (3) ASTM Standard C 150-07, approved May 1, 2007, Standard 
Specification for Portland Cement; incorporated by reference at Sec.  
250.901;
    (4) ASTM Standard C 330-05, approved December 15, 2005, Standard 
Specification for Lightweight Aggregates for Structural Concrete; 
incorporated by reference at Sec.  250.901;
    (5) ASTM Standard C 595-08, approved January 1, 2008, Standard 
Specification for Blended Hydraulic Cements; incorporated by reference 
at Sec.  250.901;
    (j) American Welding Society (AWS), AWS Codes, 550 NW, LeJeune 
Road, Miami, FL 33126; http://www.aws.org; phone: 800-443-9353:
    (1) AWS D1.1:2000, Structural Welding Code--Steel, 17th Edition, 
October 18, 1999; incorporated by reference at Sec.  250.901;
    (2) AWS D1.4-98, Structural Welding Code--Reinforcing Steel, 1998 
Edition; incorporated by reference at Sec.  250.901;
    (3) AWS D3.6M:1999, Specification for Underwater Welding (1999); 
incorporated by reference at Sec.  250.901.
    (k) National Association of Corrosion Engineers (NACE), NACE 
Standards, 1440 South Creek Drive, Houston, TX 77084; http://www.nace.org; phone: 281-228-6200:
    (1) NACE Standard MR0175-2003, Standard Material Requirements, 
Metals for Sulfide Stress Cracking and Stress Corrosion Cracking 
Resistance in Sour Oilfield Environments, Revised January 17, 2003; 
incorporated by reference at Sec. Sec.  250.901 and 250.490;
    (2) NACE Standard RP0176-2003, Standard Recommended Practice, 
Corrosion Control of Steel Fixed Offshore Structures Associated with 
Petroleum Production; incorporated by reference at Sec.  250.901.


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

    (a) OMB has approved the information collection requirements in 
part 250 under 44 U.S.C. 3501 et seq. The table in paragraph (e) of 
this section lists the subpart in the rule requiring the information 
and its title, provides the OMB control number, and summarizes the 
reasons for collecting the information and how BSEE uses the 
information. The associated BSEE forms required by this part are listed 
at the end of this table with the relevant information.
    (b) Respondents are OCS oil, gas, and sulphur lessees and 
operators. The requirement to respond to the information collections in 
this part is mandated under the Act (43 U.S.C. 1331 et seq.) and the 
Act's Amendments of 1978 (43 U.S.C. 1801 et seq.). Some responses are 
also required to obtain or retain a benefit or may be voluntary. 
Proprietary information will be protected under Sec.  250.197, Data and 
information to be made available to the public or for limited 
inspection; parts 30 CFR Parts 251, 252; and the Freedom of Information 
Act (5 U.S.C. 552) and its implementing regulations at 43 CFR part 2.
    (c) The Paperwork Reduction Act of 1995 requires us to inform the 
public that an agency may not conduct or sponsor, and you are not 
required to respond to, a collection of information unless it displays 
a currently valid OMB control number.
    (d) Send comments regarding any aspect of the collections of 
information under this part, including suggestions for reducing the 
burden, to the Information Collection Clearance Officer, Bureau of 
Safety and Environmental Enforcement, 381 Elden Street, Herndon, VA 
20170.
    (e) BSEE is collecting this information for the reasons given in 
the following table:

------------------------------------------------------------------------
 30 CFR subpart, title and/or BSEE Form       Reasons for collecting
           (OMB Control No.)                 information and how used
------------------------------------------------------------------------
(1) Subpart A, General (1010-0114),      To inform BSEE of actions taken
 including Forms BSEE-0132, Evacuation    to comply with general
 Statistics; BSEE-0143, Facility/         operational requirements on
 Equipment Damage Report; BSEE-1832,      the OCS. To ensure that
 Notification of Incidents of             operations on the OCS meet
 Noncompliance.                           statutory and regulatory
                                          requirements, are safe and
                                          protect the environment, and
                                          result in diligent
                                          exploration, development, and
                                          production on OCS leases. To
                                          support the unproved and
                                          proved reserve estimation,
                                          resource assessment, and fair
                                          market value determinations.
                                          To allow BSEE to rapidly
                                          assess damage and project any
                                          disruption of oil and gas
                                          production from the OCS after
                                          a major natural occurrence.

[[Page 64510]]

 
(2) Subpart B, Exploration and           To inform BSEE, States, and the
 Development and Production Plans (1010-  public of planned exploration,
 0151).                                   development, and production
                                          operations on the OCS. To
                                          ensure that operations on the
                                          OCS are planned to comply with
                                          statutory and regulatory
                                          requirements, will be safe and
                                          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 BSEE of measures to
 Control (1010-0057).                     be taken to prevent water
                                          pollution. To ensure that
                                          appropriate measures are taken
                                          to prevent water pollution.
(4) Subpart D, Oil and Gas and Drilling  To inform BSEE of the equipment
 Operations (1010-0141), including        and procedures to be used in
 Forms BSEE-0123, Application for         drilling operations on the
 Permit to Drill; BSEE-0123S,             OCS. To ensure that drilling
 Supplemental APD Information Sheet;      operations are safe and
 BSEE-0124, Application for Permit to     protect the human, marine, and
 Modify; BSEE-0125, End of Operations     coastal environment.
 Report; BSEE-0133, Well Activity
 Report; BSEE-0133S, Open Hole Data
 Report; and BSEE-144, Rig Movement
 Notification Report.
(5) Subpart E, Oil and Gas Well-         To inform BSEE 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 BSEE 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 BSEE 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 BSEE with
 (1010-0149).                             information regarding the
                                          design, fabrication, and
                                          installation of platforms on
                                          the OCS. To ensure the
                                          structural integrity of
                                          platforms installed on the
                                          OCS.
(9) Subpart J, Pipelines and Pipeline    To provide BSEE with
 Rights-of-Way (1010-0050), including     information regarding the
 Form BSEE-0149, Assignment of Federal    design, installation, and
 OCS Pipeline Right-of-Way Grant.         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 BSEE of production
 Rates (1010-0041), including Forms       rates for hydrocarbons
 BSEE-0126, Well Potential Test Report    produced on the OCS. To ensure
 and BSEE-0128, Semiannual Well Test      economic maximization of
 Report.                                  ultimate hydrocarbon recovery
(11) Subpart L, Oil and Gas Production   To inform BSEE 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 BSEE 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 BSEE 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 BSEE 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 BSEE-0131,         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.
------------------------------------------------------------------------


[[Page 64511]]

Subpart B--Plans and Information

General Information


Sec.  250.200  Definitions.

    Acronyms and terms used in this subpart have the following 
meanings:
    (a) Acronyms used frequently in this subpart are listed 
alphabetically below:
    BOEM means Bureau of Ocean Energy Management of the Department of 
the Interior.
    BSEE means Bureau of Safety and Environmental Enforcement of the 
Department of the Interior.
    CID means Conservation Information Document.
    CZMA means Coastal Zone Management Act.
    DOCD means Development Operations Coordination Document.
    DPP means Development and Production Plan.
    DWOP means Deepwater Operations Plan.
    EIA means Environmental Impact Analysis.
    EP means Exploration Plan.
    NPDES means National Pollutant Discharge Elimination System.
    NTL means Notice to Lessees and Operators.
    OCS means Outer Continental Shelf.
    (b) Terms used in this subpart are listed alphabetically below:
    Amendment means a change you make to an EP, DPP, or DOCD that is 
pending before BOEM for a decision (see 30 CFR 550.232(d) and 
550.267(d)).
    Modification means a change required by the Regional Supervisor to 
an EP, DPP, or DOCD (see 30 CFR 550.233(b)(2) and 550.270(b)(2)) that 
is pending before BOEM for a decision because the OCS plan is 
inconsistent with applicable requirements.
    New or unusual technology means equipment or procedures that:
    (1) Have not been used previously or extensively in a BSEE OCS 
Region;
    (2) Have not been used previously under the anticipated operating 
conditions; or
    (3) Have operating characteristics that are outside the performance 
parameters established by this part.
    Non-conventional production or completion technology includes, but 
is not limited to, floating production systems, tension leg platforms, 
spars, floating production, storage, and offloading systems, guyed 
towers, compliant towers, subsea manifolds, and other subsea production 
components that rely on a remote site or host facility for utility and 
well control services.
    Offshore vehicle means a vehicle that is capable of being driven on 
ice.
    Resubmitted OCS plan means an EP, DPP, or DOCD that contains 
changes you make to an OCS plan that BOEM has disapproved (see 30 CFR 
550.234(b), 550.272(a), and 550.273(b)).
    Revised OCS plan means an EP, DPP, or DOCD that proposes changes to 
an approved OCS plan, such as those in the location of a well or 
platform, type of drilling unit, or location of the onshore support 
base (see 30 CFR 550.283(a)).
    Supplemental OCS plan means an EP, DPP, or DOCD that proposes the 
addition to an approved OCS plan of an activity that requires approval 
of an application or permit (see 30 CFR 550.283(b)).


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

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

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

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


Sec.  250.202  [Reserved]


Sec.  250.203  [Reserved]


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

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


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

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

[[Page 64512]]

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


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

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

Deepwater Operations Plan (DWOP)


Sec.  250.286  What is a DWOP?

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


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

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


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

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


Sec.  250.289  What must the Conceptual Plan contain?

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


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

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


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

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


Sec.  250.292  What must the DWOP contain?

    You must include the following information in your DWOP:
    (a) A description and schematic of the typical wellbore, casing, 
and completion;
    (b) Structural design, fabrication, and installation information 
for each surface system, including host facilities;
    (c) Design, fabrication, and installation information on the 
mooring systems for each surface system;
    (d) Information on any active stationkeeping system(s) involving 
thrusters or other means of propulsion used with a surface system;
    (e) Information concerning the drilling and completion systems;
    (f) Design and fabrication information for each riser system (e.g., 
drilling, workover, production, and injection);
    (g) Pipeline information;
    (h) Information about the design, fabrication, and operation of an 
offtake system for transferring produced hydrocarbons to a transport 
vessel;
    (i) Information about subsea wells and associated systems that 
constitute all or part of a single project development covered by the 
DWOP;
    (j) Flow schematics and Safety Analysis Function Evaluation (SAFE) 
charts (API RP 14C, subsection 4.3c, incorporated by reference in Sec.  
250.198) of the production system from the Surface Controlled 
Subsurface Safety Valve (SCSSV) downstream to the first item of 
separation equipment;
    (k) A description of the surface/subsea safety system and emergency 
support systems to include a table that depicts what valves will close, 
at what times, and for what events or reasons;
    (l) A general description of the operating procedures, including a 
table summarizing the curtailment of production and offloading based on 
operational considerations;
    (m) A description of the facility installation and commissioning 
procedure;
    (n) A discussion of any new technology that affects hydrocarbon 
recovery systems;
    (o) A list of any alternate compliance procedures or departures for 
which you anticipate requesting approval; and
    (p) Payment of the service fee listed in Sec.  250.125.


Sec.  250.293  What operations require approval of the DWOP?

    You may not begin production until BSEE approves your DWOP.


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

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


Sec.  250.295  When must I revise my DWOP?

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

Subpart C--Pollution Prevention and Control


Sec.  250.300  Pollution prevention.

    (a) During the exploration, development, production, and 
transportation of oil and gas or sulphur,

[[Page 64513]]

the lessee shall take measures to prevent unauthorized discharge of 
pollutants into the offshore waters. The lessee shall not create 
conditions that will pose unreasonable risk to public health, life, 
property, aquatic life, wildlife, recreation, navigation, commercial 
fishing, or other uses of the ocean.
    (1) When pollution occurs as a result of operations conducted by or 
on behalf of the lessee and the pollution damages or threatens to 
damage life (including fish and other aquatic life), property, any 
mineral deposits (in areas leased or not leased), or the marine, 
coastal, or human environment, the control and removal of the pollution 
to the satisfaction of the District Manager shall be at the expense of 
the lessee. Immediate corrective action shall be taken in all cases 
where pollution has occurred. Corrective action shall be subject to 
modification when directed by the District Manager.
    (2) If the lessee fails to control and remove the pollution, the 
Director, in cooperation with other appropriate Agencies of Federal, 
State, and local governments, or in cooperation with the lessee, or 
both, shall have the right to control and remove the pollution at the 
lessee's expense. Such action shall not relieve the lessee of any 
responsibility provided for by law.
    (b)(1) The District Manager may restrict the rate of drilling fluid 
discharges or prescribe alternative discharge methods. The District 
Manager may also restrict the use of components which could cause 
unreasonable degradation to the marine environment. No petroleum-based 
substances, including diesel fuel, may be added to the drilling mud 
system without prior approval of the District Manager.
    (2) Approval of the method of disposal of drill cuttings, sand, and 
other well solids shall be obtained from the District Manager.
    (3) All hydrocarbon-handling equipment for testing and production 
such as separators, tanks, and treaters shall be designed, installed, 
and operated to prevent pollution. Maintenance or repairs which are 
necessary to prevent pollution of offshore waters shall be undertaken 
immediately.
    (4) Curbs, gutters, drip pans, and drains shall be installed in 
deck areas in a manner necessary to collect all contaminants not 
authorized for discharge. Oil drainage shall be piped to a properly 
designed, operated, and maintained sump system which will automatically 
maintain the oil at a level sufficient to prevent discharge of oil into 
offshore waters. All gravity drains shall be equipped with a water trap 
or other means to prevent gas in the sump system from escaping through 
the drains. Sump piles shall not be used as processing devices to treat 
or skim liquids but may be used to collect treated-produced water, 
treated-produced sand, or liquids from drip pans and deck drains and as 
a final trap for hydrocarbon liquids in the event of equipment upsets. 
Improperly designed, operated, or maintained sump piles which do not 
prevent the discharge of oil into offshore waters shall be replaced or 
repaired.
    (5) On artificial islands, all vessels containing hydrocarbons 
shall be placed inside an impervious berm or otherwise protected to 
contain spills. Drainage shall be directed away from the drilling rig 
to a sump. Drains and sumps shall be constructed to prevent seepage.
    (6) Disposal of equipment, cables, chains, containers, or other 
materials into offshore waters is prohibited.
    (c) Materials, equipment, tools, containers, and other items used 
in the Outer Continental Shelf (OCS) which are of such shape or 
configuration that they are likely to snag or damage fishing devices 
shall be handled and marked as follows:
    (1) All loose material, small tools, and other small objects shall 
be kept in a suitable storage area or a marked container when not in 
use and in a marked container before transport over offshore waters;
    (2) All cable, chain, or wire segments shall be recovered after use 
and securely stored until suitable disposal is accomplished;
    (3) Skid-mounted equipment, portable containers, spools or reels, 
and drums shall be marked with the owner's name prior to use or 
transport over offshore waters; and
    (4) All markings must clearly identify the owner and must be 
durable enough to resist the effects of the environmental conditions to 
which they may be exposed.
    (d) Any of the items described in paragraph (c) of this section 
that are lost overboard shall be recorded on the facility's daily 
operations report, as appropriate, and reported to the District 
Manager.


Sec.  250.301  Inspection of facilities.

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

Subpart D--Oil and Gas Drilling Operations

General Requirements


Sec.  250.400  Who is subject to the requirements of this subpart?

    The requirements of this subpart apply to lessees, operating rights 
owners, operators, and their contractors and subcontractors.


Sec.  250.401  What must I do to keep wells under control?

    You must take necessary precautions to keep wells under control at 
all times. You must:
    (a) Use the best available and safest drilling technology to 
monitor and evaluate well conditions and to minimize the potential for 
the well to flow or kick;
    (b) Have a person onsite during drilling operations who represents 
your interests and can fulfill your responsibilities;
    (c) Ensure that the toolpusher, operator's representative, or a 
member of the drilling crew maintains continuous surveillance on the 
rig floor from the beginning of drilling operations until the well is 
completed or abandoned, unless you have secured the well with blowout 
preventers (BOPs), bridge plugs, cement plugs, or packers;
    (d) Use personnel trained according to the provisions of subpart O; 
and
    (e) Use and maintain equipment and materials necessary to ensure 
the safety and protection of personnel, equipment, natural resources, 
and the environment.


Sec.  250.402  When and how must I secure a well?

    Whenever you interrupt drilling operations, you must install a 
downhole safety device, such as a cement plug, bridge plug, or packer. 
You must install the device at an appropriate depth within a properly 
cemented casing string or liner.
    (a) Among the events that may cause you to interrupt drilling 
operations are:
    (1) Evacuation of the drilling crew;
    (2) Inability to keep the drilling rig on location; or
    (3) Repair to major drilling or well-control equipment.
    (b) For floating drilling operations, the District Manager may 
approve the use of blind or blind-shear rams or pipe rams and an inside 
BOP if you don't have time to install a downhole safety device or if 
special circumstances occur.


Sec.  250.403  What drilling unit movements must I report?

    (a) You must report the movement of all drilling units on and off 
drilling

[[Page 64514]]

locations to the District Manager. This includes both MODU and platform 
rigs. You must inform the District Manager 24 hours before:
    (1) The arrival of an MODU on location;
    (2) The movement of a platform rig to a platform;
    (3) The movement of a platform rig to another slot;
    (4) The movement of an MODU to another slot; and
    (5) The departure of an MODU from the location.
    (b) You must provide the District Manager with the rig name, lease 
number, well number, and expected time of arrival or departure.
    (c) In the Gulf of Mexico OCS Region, you must report drilling unit 
movements on form BSEE-0144, Rig Movement Notification Report.


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

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


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

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


Sec.  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?

    You must take the following safety measures when you conduct 
drilling operations on a platform with producing wells or that has 
other hydrocarbon flow:
    (a) You must install an emergency shutdown station near the 
driller's console;
    (b) You must shut in all producible wells located in the affected 
wellbay below the surface and at the wellhead when:
    (1) You move a drilling rig or related equipment on and off a 
platform. This includes rigging up and rigging down activities within 
500 feet of the affected platform;
    (2) You move or skid a drilling unit between wells on a platform;
    (3) A mobile offshore drilling unit (MODU) moves within 500 feet of 
a platform. You may resume production once the MODU is in place, 
secured, and ready to begin drilling operations.


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

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


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

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


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

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

Applying for a Permit To Drill


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

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


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

    In addition to forms BSEE-0123 and BSEE-0123S, you must include the 
information described in the following table.

------------------------------------------------------------------------
 Information that you must  include with
                  an APD                    Where to find a description
------------------------------------------------------------------------
(a) Plat that shows locations of the       Sec.   250.412
 proposed well.
(b) Design criteria used for the proposed  Sec.   250.413
 well.
(c) Drilling prognosis...................  Sec.   250.414
(d) Casing and cementing programs........  Sec.   250.415
(e) Diverter and BOP systems descriptions  Sec.   250.416
(f) Requirements for using an MODU.......  Sec.   250.417
(g) Additional information...............  Sec.   250.418
------------------------------------------------------------------------

Sec.  250.412  What requirements must the location plat meet?

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

[[Page 64515]]

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

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


Sec.  250.414  What must my drilling prognosis include?

    Your drilling prognosis must include a brief description of the 
procedures you will follow in drilling the well. This prognosis 
includes but is not limited to the following:
    (a) Projected plans for coring at specified depths;
    (b) Projected plans for logging;
    (c) Planned safe drilling margin between proposed drilling fluid 
weights and estimated pore pressures. This safe drilling margin may be 
shown on the plot required by Sec.  250.413(g);
    (d) Estimated depths to the top of significant marker formations;
    (e) Estimated depths to significant porous and permeable zones 
containing fresh water, oil, gas, or abnormally pressured formation 
fluids;
    (f) Estimated depths to major faults;
    (g) Estimated depths of permafrost, if applicable;
    (h) A list and description of all requests for using alternative 
procedures or departures from the requirements of this subpart in one 
place in the APD. You must explain how the alternative procedures 
afford an equal or greater degree of protection, safety, or 
performance, or why you need the departures; and
    (i) Projected plans for well testing (refer to Sec.  250.460 for 
safety requirements).


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

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


Sec.  250.416   What must I include in the diverter and BOP 
descriptions?

    You must include in the diverter and BOP descriptions:
    (a) A description of the diverter system and its operating 
procedures;
    (b) A schematic drawing of the diverter system (plan and elevation 
views) that shows:
    (1) The size of the annular BOP installed in the diverter housing;
    (2) Spool outlet internal diameter(s);
    (3) Diverter-line lengths and diameters; burst strengths and radius 
of curvature at each turn; and
    (4) Valve type, size, working pressure rating, and location;
    (c) A description of the BOP system and system components, 
including pressure ratings of BOP equipment and proposed BOP test 
pressures;
    (d) A schematic drawing of the BOP system that shows the inside 
diameter of the BOP stack, number and type of preventers, all control 
systems and pods, location of choke and kill lines, and associated 
valves;
    (e) Independent third party verification and supporting 
documentation that show the blind-shear rams installed in the BOP stack 
are capable of shearing any drill pipe in the hole under maximum 
anticipated surface pressure. The documentation must include test 
results and calculations of shearing capacity of all pipe to be used in 
the well including correction for MASP;
    (f) When you use a subsea BOP stack, independent third party 
verification that shows:
    (1) The BOP stack is designed for the specific equipment on the rig 
and for the specific well design;
    (2) The BOP stack has not been compromised or damaged from previous 
service;
    (3) The BOP stack will operate in the conditions in which it will 
be used; and
    (g) The qualifications of the independent third party referenced in 
paragraphs (e) and (f) of this section:
    (1) The independent third party in paragraph (e) in this section 
must be a technical classification society; an API-licensed 
manufacturing, inspection, or certification firm; or a licensed 
professional engineering firm capable of providing the verifications 
required under this part. The independent third party must not be the 
original equipment manufacturer (OEM).
    (2) You must:
    (i) Include evidence that the firm you are using is reputable, the 
firm or its employees hold appropriate licenses to perform the 
verification in the appropriate jurisdiction, the firm carries 
industry-standard levels of professional liability insurance, and the 
firm has no record of violations of applicable law.
    (ii) Ensure that an official representative of BSEE will have 
access to the location to witness any testing or inspections, and 
verify information

[[Page 64516]]

submitted to BSEE. Prior to any shearing ram tests or inspections, you 
must notify the District Manager at least 24 hours in advance.


Sec.  250.417  What must I provide if I plan to use a mobile offshore 
drilling unit (MODU)?

    If you plan to use a MODU, you must provide:
    (a) Fitness requirements. You must provide information and data to 
demonstrate the drilling unit's capability to perform at the proposed 
drilling location. This information must include the maximum 
environmental and operational conditions that the unit is designed to 
withstand, including the minimum air gap necessary for both hurricane 
and non-hurricane seasons. If sufficient environmental information and 
data are not available at the time you submit your APD, the District 
Manager may approve your APD but require you to collect and report this 
information during operations. Under this circumstance, the District 
Manager has the right to revoke the approval of the APD if information 
collected during operations show that the drilling unit is not capable 
of performing at the proposed location.
    (b) Foundation requirements. You must provide information to show 
that site-specific soil and oceanographic conditions are capable of 
supporting the proposed drilling unit. If you provided sufficient site-
specific information in your EP, DPP, or DOCD submitted to BOEM, you 
may reference that information. The District Manager may require you to 
conduct additional surveys and soil borings before approving the APD if 
additional information is needed to make a determination that the 
conditions are capable of supporting the drilling unit.
    (c) Frontier areas. (1) If the design of the drilling unit you plan 
to use in a frontier area is unique or has not been proven for use in 
the proposed environment, the District Manager may require you to 
submit a third-party review of the unit's design. If required, you must 
obtain the third-party review according to Sec. Sec.  250.915 through 
250.918. You may submit this information before submitting an APD.
    (2) If you plan to drill in a frontier area, you must have a 
contingency plan that addresses design and operating limitations of the 
drilling unit. Your plan must identify the actions necessary to 
maintain safety and prevent damage to the environment. Actions must 
include the suspension, curtailment, or modification of drilling or rig 
operations to remedy various operational or environmental situations 
(e.g., vessel motion, riser offset, anchor tensions, wind speed, wave 
height, currents, icing or ice-loading, settling, tilt or lateral 
movement, resupply capability).
    (d) U.S. Coast Guard (USCG) documentation. You must provide the 
current Certificate of Inspection or Letter of Compliance from the 
USCG. You must also provide current documentation of any operational 
limitations imposed by an appropriate classification society.
    (e) Floating drilling unit. If you use a floating drilling unit, 
you must indicate that you have a contingency plan for moving off 
location in an emergency situation.
    (f) Inspection of unit. The drilling unit must be available for 
inspection by the District Manager before commencing operations.
    (g) Once the District Manager has approved a MODU for use, you do 
not need to re-submit the information required by this section for 
another APD to use the same MODU unless changes in equipment affect its 
rated capacity to operate in the District.


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

    You must include the following with the APD:
    (a) Rated capacities of the drilling rig and major drilling 
equipment, if not already on file with the appropriate District office;
    (b) A drilling fluids program that includes the minimum quantities 
of drilling fluids and drilling fluid materials, including weight 
materials, to be kept at the site;
    (c) A proposed directional plot if the well is to be directionally 
drilled;
    (d) A Hydrogen Sulfide Contingency Plan (see Sec.  250.490), if 
applicable, and not previously submitted;
    (e) A welding plan (see Sec. Sec.  250.109 to 250.113) if not 
previously submitted;
    (f) In areas subject to subfreezing conditions, evidence that the 
drilling equipment, BOP systems and components, diverter systems, and 
other associated equipment and materials are suitable for operating 
under such conditions;
    (g) A request for approval if you plan to wash out or displace some 
cement to facilitate casing removal upon well abandonment;
    (h) Certification of your casing and cementing program as required 
in Sec.  250.420(a)(6);
    (i) Description of qualifications required by Sec.  250.416(f) of 
any independent third party; and
    (j) Such other information as the District Manager may require.

Casing and Cementing Requirements


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

    You must case and cement all wells. Your casing and cementing 
programs must meet the requirements of this section and of Sec. Sec.  
250.421 through 250.428.
    (a) Casing and cementing program requirements. Your casing and 
cementing programs must:
    (1) Properly control formation pressures and fluids;
    (2) Prevent the direct or indirect release of fluids from any 
stratum through the wellbore into offshore waters;
    (3) Prevent communication between separate hydrocarbon-bearing 
strata;
    (4) Protect freshwater aquifers from contamination;
    (5) Support unconsolidated sediments; and
    (6) Include certification signed by a Registered Professional 
Engineer that there will be at least two independent tested barriers, 
including one mechanical barrier, across each flow path during well 
completion activities and that the casing and cementing design is 
appropriate for the purpose for which it is intended under expected 
wellbore conditions. The Registered Professional Engineer must be 
registered in a State in the United States. Submit this certification 
with your APD (Form BSEE-0123).
    (b) Casing requirements. (1) You must design casing (including 
liners) to withstand the anticipated stresses imposed by tensile, 
compressive, and buckling loads; burst and collapse pressures; thermal 
effects; and combinations thereof.
    (2) The casing design must include safety measures that ensure well 
control during drilling and safe operations during the life of the 
well.
    (3) For the final casing string (or liner if it is your final 
string), you must install dual mechanical barriers in addition to 
cement, to prevent flow in the event of a failure in the cement. These 
may include dual float valves, or one float valve and a mechanical 
barrier. You must submit documentation to BSEE 30 days after 
installation of the dual mechanical barriers.
    (c) Cementing requirements. You must design and conduct your 
cementing jobs so that cement composition, placement techniques, and 
waiting times ensure that the cement placed behind the bottom 500 feet 
of casing attains a minimum compressive strength of 500 psi before 
drilling out of the casing or before commencing completion operations.

[[Page 64517]]

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

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

------------------------------------------------------------------------
                                                          Cementing
         Casing type           Casing requirements      requirements
------------------------------------------------------------------------
(a) Drive or Structural.....  Set by driving,       If you drilled a
                               jetting, or           portion of this
                               drilling to the       hole, you must use
                               minimum depth as      enough cement to
                               approved or           fill the annular
                               prescribed by the     space back to the
                               District Manager.     mudline.
(b) Conductor...............  Design casing and     Use enough cement to
                               select setting        fill the calculated
                               depths based on       annular space back
                               relevant              to the mudline.
                               engineering and      Verify annular fill
                               geologic factors.     by observing cement
                               These factors         returns. If you
                               include the           cannot observe
                               presence or absence   cement returns, use
                               of hydrocarbons,      additional cement
                               potential hazards,    to ensure fill-back
                               and water depths;     to the mudline.
                              Set casing            For drilling on an
                               immediately before    artificial island
                               drilling into         or when using a
                               formations known to   glory hole, you
                               contain oil or gas.   must discuss the
                               If you encounter      cement fill level
                               oil or gas or         with the District
                               unexpected            Manager.
                               formation pressure
                               before the planned
                               casing point, you
                               must set casing
                               immediately.
(c) Surface.................  Design casing and     Use enough cement to
                               select setting        fill the calculated
                               depths based on       annular space to at
                               relevant              least 200 feet
                               engineering and       inside the
                               geologic factors.     conductor casing.
                               These factors        When geologic
                               include the           conditions such as
                               presence or absence   near-surface
                               of hydrocarbons,      fractures and
                               potential hazards,    faulting exist, you
                               and water depths.     must use enough
                                                     cement to fill the
                                                     calculated annular
                                                     space to the
                                                     mudline.
(d) Intermediate............  Design casing and     Use enough cement to
                               select setting        cover and isolate
                               depth based on        all hydrocarbon-
                               anticipated or        bearing zones and
                               encountered           isolate abnormal
                               geologic              pressure intervals
                               characteristics or    from normal
                               wellbore conditions.  pressure intervals
                                                     in the well.
                                                    As a minimum, you
                                                     must cement the
                                                     annular space 500
                                                     feet above the
                                                     casing shoe and 500
                                                     feet above each
                                                     zone to be
                                                     isolated.
(e) Production..............  Design casing and     Use enough cement to
                               select setting        cover or isolate
                               depth based on        all hydrocarbon-
                               anticipated or        bearing zones above
                               encountered           the shoe.
                               geologic             As a minimum, you
                               characteristics or    must cement the
                               wellbore conditions.  annular space at
                                                     least 500 feet
                                                     above the casing
                                                     shoe and 500 feet
                                                     above the uppermost
                                                     hydrocarbon-bearing
                                                     zone.
(f) Liners..................  If you use a liner    Same as cementing
                               as conductor or       requirements for
                               surface casing, you   specific casing
                               must set the top of   types. For example,
                               the liner at least    a liner used as
                               200 feet above the    intermediate casing
                               previous casing/      must be cemented
                               liner shoe.           according to the
                              If you use a liner     cementing
                               as an intermediate    requirements for
                               string below a        intermediate
                               surface string or     casing.
                               production casing
                               below an
                               intermediate
                               string, you must
                               set the top of the
                               liner at least 100
                               feet above the
                               previous casing
                               shoe.
------------------------------------------------------------------------

Sec.  250.422  When may I resume drilling after cementing?

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


Sec.  250.423  What are the requirements for pressure testing casing?

    (a) The table in this section describes the minimum test pressures 
for each string of casing. You may not resume drilling or other down-
hole operations until you obtain a satisfactory pressure test. If the 
pressure declines more than 10 percent in a 30-minute test, or if there 
is another indication of a leak, you must re-cement, repair the casing, 
or run additional casing to provide a proper seal. The District Manager 
may approve or require other casing test pressures.

------------------------------------------------------------------------
              Casing type                     Minimum test pressure
------------------------------------------------------------------------
(1) Drive or Structural................  Not required.
(2) Conductor..........................  200 psi.
(3) Surface, Intermediate, and           70 percent of its minimum
 Production.                              internal yield.
------------------------------------------------------------------------

    (b) You must ensure proper installation of casing or liner in the 
subsea wellhead or liner hanger.
    (1) You must ensure that the latching mechanisms or lock down 
mechanisms are engaged upon installation of each casing string or 
liner.
    (2) You must perform a pressure test on the casing seal assembly to 
ensure proper installation of casing or liner. You must perform this 
test for the

[[Page 64518]]

intermediate and production casing strings or liner.
    (3) You must submit for approval with your APD, test procedures and 
criteria for a successful test.
    (4) You must document all your test results and make them available 
to BSEE upon request.
    (c) You must perform a negative pressure test on all wells to 
ensure proper casing installation. You must perform this test for the 
intermediate and production casing strings.
    (1) You must submit for approval with your APD, test procedures and 
criteria for a successful test.
    (2) You must document all your test results and make them available 
to BSEE upon request.


Sec.  250.424  What are the requirements for prolonged drilling 
operations?

    If wellbore operations continue for more than 30 days within a 
casing string run to the surface:
    (a) You must stop drilling operations as soon as practicable, and 
evaluate the effects of the prolonged operations on continued drilling 
operations and the life of the well. At a minimum, you must:
    (1) Caliper or pressure test the casing; and
    (2) Report the results of your evaluation to the District Manager 
and obtain approval of those results before resuming operations.
    (b) If casing integrity has deteriorated to a level below minimum 
safety factors, you must:
    (1) Repair the casing or run another casing string; and
    (2) Obtain approval from the District Manager before you begin 
repairs.


Sec.  250.425  What are the requirements for pressure testing liners?

    (a) You must test each drilling liner (and liner-lap) to a pressure 
at least equal to the anticipated pressure to which the liner will be 
subjected during the formation pressure-integrity test below that liner 
shoe, or subsequent liner shoes if set. The District Manager may 
approve or require other liner test pressures.
    (b) You must test each production liner (and liner-lap) to a 
minimum of 500 psi above the formation fracture pressure at the casing 
shoe into which the liner is lapped.
    (c) You may not resume drilling or other down-hole operations until 
you obtain a satisfactory pressure test. If the pressure declines more 
than 10 percent in a 30-minute test or if there is another indication 
of a leak, you must re-cement, repair the liner, or run additional 
casing/liner to provide a proper seal.


Sec.  250.426  What are the recordkeeping requirements for casing and 
liner pressure tests?

    You must record the time, date, and results of each pressure test 
in the driller's report maintained under standard industry practice. In 
addition, you must record each test on a pressure chart and have your 
onsite representative sign and date the test as being correct.


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

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


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

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

------------------------------------------------------------------------
 If you encounter the following situation:       Then you must . . .
------------------------------------------------------------------------
(a) Have unexpected formation pressures or  Submit a revised casing
 conditions that warrant revising your       program to the District
 casing design,                              Manager for approval.
(b) Need to increase casing setting depths  Submit those changes to the
 more than 100 feet true vertical depth      District Manager for
 (TVD) from the approved APD due to          approval.
 conditions encountered during drilling
 operations,
(c) Have indication of inadequate cement    (1) Pressure test the casing
 job (such as lost returns, cement           shoe; (2) Run a temperature
 channeling, or failure of equipment),       survey; (3) Run a cement
                                             bond log; or (4) Use a
                                             combination of these
                                             techniques.
(d) Inadequate cement job,                  Re-cement or take other
                                             remedial actions as
                                             approved by the District
                                             Manager.
(e) Primary cement job that did not         Isolate those intervals from
 isolate abnormal pressure intervals,        normal pressures by squeeze
                                             cementing before you
                                             complete; suspend
                                             operations; or abandon the
                                             well, whichever occurs
                                             first.
(f) Decide to produce a well that was not   Have at least two cemented
 originally contemplated for production,     casing strings (does not
                                             include liners) in the
                                             well. Note: All producing
                                             wells must have at least
                                             two cemented casing
                                             strings.
(g) Want to drill a well without setting    Submit geologic data and
 conductor casing,                           information to the District
                                             Manager that demonstrates
                                             the absence of shallow
                                             hydrocarbons or hazards.
                                             This information must
                                             include logging and
                                             drilling fluid-monitoring
                                             from wells previously
                                             drilled within 500 feet of
                                             the proposed well path down
                                             to the next casing point.
(h) Need to use less than required cement   Submit information to the
 for the surface casing during floating      District Manager that
 drilling operations to provide protection   demonstrates the use of
 from burst and collapse pressures,          less cement is necessary.
(i) Cement across a permafrost zone,        Use cement that sets before
                                             it freezes and has a low
                                             heat of hydration.

[[Page 64519]]

 
(j) Leave the annulus opposite a            Fill the annulus with a
 permafrost zone uncemented,                 liquid that has a freezing
                                             point below the minimum
                                             permafrost temperature and
                                             minimizes opposite a
                                             corrosion.
------------------------------------------------------------------------

Diverter System Requirements


Sec.  250.430  When must I install a diverter system?

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


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

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


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

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

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

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

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


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

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

Blowout Preventer (BOP) System Requirements


Sec.  250.440  What are the general requirements for BOP systems and 
system components?

    You must design, install, maintain, test, and use the BOP system 
and system components to ensure well control. The working-pressure 
rating of each BOP component must exceed maximum anticipated surface 
pressures. The BOP system includes the BOP stack and associated BOP 
systems and equipment.


Sec.  250.441  What are the requirements for a surface BOP stack?

    (a) When you drill with a surface BOP stack, you must install the 
BOP system before drilling below surface casing. The surface BOP stack 
must include at least four remote-controlled, hydraulically operated 
BOPs, consisting of an annular BOP, two BOPs equipped with pipe rams, 
and one BOP equipped with blind or blind-shear rams.
    (b) Your surface BOP stack must include at least four remote-
controlled, hydraulically operated BOPs consisting of an annular BOP, 
two BOPs equipped with pipe rams, and one BOP equipped with blind-shear 
rams. The blind-shear rams must be capable of shearing the drill pipe 
that is in the hole.
    (c) You must install an accumulator system that provides 1.5 times 
the volume of fluid capacity necessary to close and hold closed all BOP 
components. The system must perform with a minimum pressure of 200 psi 
above the precharge pressure without assistance from a charging system. 
If you supply the accumulator regulators by rig air and do not have a 
secondary source of pneumatic supply, you must equip the regulators 
with manual

[[Page 64520]]

overrides or other devices to ensure capability of hydraulic operations 
if rig air is lost.
    (d) In addition to the stack and accumulator system, you must 
install the associated BOP systems and equipment required by the 
regulations in this subpart.


Sec.  250.442  What are the requirements for a subsea BOP system?

    When you drill with a subsea BOP system, you must install the BOP 
system before drilling below the surface casing. The District Manager 
may require you to install a subsea BOP system before drilling below 
the conductor casing if proposed casing setting depths or local geology 
indicate the need. The table in this paragraph outlines your 
requirements.

------------------------------------------------------------------------
When drilling with a subsea BOP system,
               you must:                     Additional requirements
------------------------------------------------------------------------
(a) Have at least four remote-           You must have at least one
 controlled, hydraulically operated       annular BOP, two BOPs equipped
 BOPs.                                    with pipe rams, and one BOP
                                          equipped with blind-shear
                                          rams. The blind-shear rams
                                          must be capable of shearing
                                          any drill pipe in the hole
                                          under maximum anticipated
                                          surface pressures.
(b) Have an operable dual-pod control    ...............................
 system to ensure proper and
 independent operation of the BOP
 system.
(c) Have an accumulator system to        The accumulator system must
 provide fast closure of the BOP          meet or exceed the provisions
 components and to operate all critical   of Section 13.3, Accumulator
 functions in case of a loss of the       Volumetric Capacity, in API RP
 power fluid connection to the surface.   53, Recommended Practices for
                                          Blowout Prevention Equipment
                                          Systems for Drilling Wells (as
                                          incorporated by reference in
                                          Sec.   250.198). The District
                                          Manager may approve a suitable
                                          alternate method.
(d) Have a subsea BOP stack equipped     At a minimum, the ROV must be
 with remotely operated vehicle (ROV)     capable of closing one set of
 intervention capability.                 pipe rams, closing one set of
                                          blind-shear rams and
                                          unlatching the LMRP.
(e) Maintain an ROV and have a trained   The crew must be trained in the
 ROV crew on each floating drilling rig   operation of the ROV. The
 on a continuous basis. The crew must     training must include
 examine all ROV related well control     simulator training on stabbing
 equipment (both surface and subsea) to   into an ROV intervention panel
 ensure that it is properly maintained    on a subsea BOP stack.
 and capable of shutting in the well
 during emergency operations.
(f) Provide autoshear and deadman        (1) Autoshear system means a
 systems for dynamically positioned       safety system that is designed
 rigs.                                    to automatically shut in the
                                          wellbore in the event of a
                                          disconnect of the LMRP. When
                                          the autoshear is armed, a
                                          disconnect of the LMRP closes
                                          the shear rams. This is
                                          considered a ``rapid
                                          discharge'' system.
                                         (2) Deadman System means a
                                          safety system that is designed
                                          to automatically close the
                                          wellbore in the event of a
                                          simultaneous absence of
                                          hydraulic supply and signal
                                          transmission capacity in both
                                          subsea control pods. This is
                                          considered a ``rapid
                                          discharge'' system.
                                         (3) You may also have an
                                          acoustic system.
(g) Have operational or physical         Incorporate enable buttons on
 barrier(s) on BOP control panels to      control panels to ensure two-
 prevent accidental disconnect            handed operation for all
 functions.                               critical functions.
(h) Clearly label all control panels     Label other BOP control panels
 for the subsea BOP system.               such as hydraulic control
                                          panel.
(i) Develop and use a management system  The management system must
 for operating the BOP system,            include written procedures for
 including the prevention of accidental   operating the BOP stack and
 or unplanned disconnects of the system.  LMRP (including proper
                                          techniques to prevent
                                          accidental disconnection of
                                          these components) and minimum
                                          knowledge requirements for
                                          personnel authorized to
                                          operate and maintain BOP
                                          components.
(j) Establish minimum requirements for   Personnel must have:
 personnel authorized to operate
 critical BOP equipment.
                                         (1) Training in deepwater well
                                          control theory and practice
                                          according to the requirements
                                          of 30 CFR 250, subpart O; and
                                         (2) A comprehensive knowledge
                                          of BOP hardware and control
                                          systems.
(k) Before removing the marine riser,    You must maintain sufficient
 displace the fluid in the riser with     hydrostatic pressure or take
 seawater.                                other suitable precautions to
                                          compensate for the reduction
                                          in pressure and to maintain a
                                          safe and controlled well
                                          condition.
(l) Install the BOP stack in a glory     Your glory hole must be deep
 hole when in ice-scour area.             enough to ensure that the top
                                          of the stack is below the
                                          deepest probable ice-scour
                                          depth.
------------------------------------------------------------------------

Sec.  250.443  What associated systems and related equipment must all 
BOP systems include?

    All BOP systems must include the following associated systems and 
related equipment:
    (a) An automatic backup to the primary accumulator-charging system. 
The power source must be independent from the power source for the 
primary accumulator-charging system. The independent power source must 
possess sufficient capability to close and hold closed all BOP 
components.
    (b) At least two BOP control stations. One station must be on the 
drilling floor. You must locate the other station in a readily 
accessible location away from the drilling floor.
    (c) Side outlets on the BOP stack for separate kill and choke 
lines. If your stack does not have side outlets, you must install a 
drilling spool with side outlets.
    (d) A choke and a kill line on the BOP stack. You must equip each 
line with two full-opening valves, one of which must be remote-
controlled. For a subsea BOP system, both valves in each line must be 
remote-controlled. In addition:
    (1) You must install the choke line above the bottom ram;
    (2) You may install the kill line below the bottom ram; and
    (3) For a surface BOP system, on the kill line you may install a 
check valve and a manual valve instead of the

[[Page 64521]]

remote-controlled valve. To use this configuration, both manual valves 
must be readily accessible and you must install the check valve between 
the manual valves and the pump.
    (e) A fill-up line above the uppermost BOP.
    (f) Locking devices installed on the ram-type BOPs.
    (g) A wellhead assembly with a rated working pressure that exceeds 
the maximum anticipated surface pressure.


Sec.  250.444  What are the choke manifold requirements?

    (a) Your BOP system must include a choke manifold that is suitable 
for the anticipated surface pressures, anticipated methods of well 
control, the surrounding environment, and the corrosiveness, volume, 
and abrasiveness of drilling fluids and well fluids that you may 
encounter.
    (b) Choke manifold components must have a rated working pressure at 
least as great as the rated working pressure of the ram BOPs. If your 
choke manifold has buffer tanks downstream of choke assemblies, you 
must install isolation valves on any bleed lines.
    (c) Valves, pipes, flexible steel hoses, and other fittings 
upstream of the choke manifold must have a rated working pressure at 
least as great as the rated working pressure of the ram BOPs.


Sec.  250.445  What are the requirements for kelly valves, inside BOPs, 
and drill-string safety valves?

    You must use or provide the following BOP equipment during drilling 
operations:
    (a) A kelly valve installed below the swivel (upper kelly valve);
    (b) A kelly valve installed at the bottom of the kelly (lower kelly 
valve). You must be able to strip the lower kelly valve through the BOP 
stack;
    (c) If you drill with a mud motor and use drill pipe instead of a 
kelly, you must install one kelly valve above, and one strippable kelly 
valve below, the joint of drill pipe used in place of a kelly;
    (d) On a top-drive system equipped with a remote-controlled valve, 
you must install a strippable kelly-type valve below the remote-
controlled valve;
    (e) An inside BOP in the open position located on the rig floor. 
You must be able to install an inside BOP for each size connection in 
the drill string;
    (f) A drill-string safety valve in the open position located on the 
rig floor. You must have a drill-string safety valve available for each 
size connection in the drill string;
    (g) When running casing, you must have a safety valve in the open 
position available on the rig floor to fit the casing string being run 
in the hole;
    (h) All required manual and remote-controlled kelly valves, drill-
string safety valves, and comparable-type valves (i.e., kelly-type 
valve in a top-drive system) must be essentially full-opening; and
    (i) The drilling crew must have ready access to a wrench to fit 
each manual valve.


Sec.  250.446  What are the BOP maintenance and inspection 
requirements?

    (a) You must maintain and inspect your BOP system to ensure that 
the equipment functions properly. The BOP maintenance and inspections 
must meet or exceed the provisions of Sections 17.10 and 18.10, 
Inspections; Sections 17.11 and 18.11, Maintenance; and Sections 17.12 
and 18.12, Quality Management, described in API RP 53, Recommended 
Practices for Blowout Prevention Equipment Systems for Drilling Wells 
(as incorporated by reference in Sec.  250.198). You must document the 
procedures used, record the results of your BOP inspections and 
maintenance actions, and make available to BSEE upon request. You must 
maintain your records on the rig for 2 years or from the date of your 
last major inspection, whichever is longer;
    (b) You must visually inspect your surface BOP system on a daily 
basis. You must visually inspect your subsea BOP system and marine 
riser at least once every 3 days if weather and sea conditions permit. 
You may use television cameras to inspect subsea equipment.


Sec.  250.447  When must I pressure test the BOP system?

    You must pressure test your BOP system (this includes the choke 
manifold, kelly valves, inside BOP, and drill-string safety valve):
    (a) When installed;
    (b) Before 14 days have elapsed since your last BOP pressure test. 
You must begin to test your BOP system before midnight on the 14th day 
following the conclusion of the previous test. However, the District 
Manager may require more frequent testing if conditions or BOP 
performance warrant; and
    (c) Before drilling out each string of casing or a liner. The 
District Manager may allow you to omit this test if you didn't remove 
the BOP stack to run the casing string or liner and the required BOP 
test pressures for the next section of the hole are not greater than 
the test pressures for the previous BOP test. You must indicate in your 
APD which casing strings and liners meet these criteria.


Sec.  250.448  What are the BOP pressure tests requirements?

    When you pressure test the BOP system, you must conduct a low-
pressure and a high-pressure test for each BOP component. You must 
conduct the low-pressure test before the high-pressure test. Each 
individual pressure test must hold pressure long enough to demonstrate 
that the tested component(s) holds the required pressure. Required test 
pressures are as follows:
    (a) Low-pressure test. All low-pressure tests must be between 200 
and 300 psi. Any initial pressure above 300 psi must be bled back to a 
pressure between 200 and 300 psi before starting the test. If the 
initial pressure exceeds 500 psi, you must bleed back to zero and 
reinitiate the test.
    (b) High-pressure test for ram-type BOPs, the choke manifold, and 
other BOP components. The high-pressure test must equal the rated 
working pressure of the equipment or be 500 psi greater than your 
calculated maximum anticipated surface pressure (MASP) for the 
applicable section of hole. Before you may test BOP equipment to the 
MASP plus 500 psi, the District Manager must have approved those test 
pressures in your APD.
    (c) High pressure test for annular-type BOPs. The high pressure 
test must equal 70 percent of the rated working pressure of the 
equipment or to a pressure approved in your APD.
    (d) Duration of pressure test. Each test must hold the required 
pressure for 5 minutes. However, for surface BOP systems and surface 
equipment of a subsea BOP system, a 3-minute test duration is 
acceptable if you record your test pressures on the outermost half of a 
4-hour chart, on a 1-hour chart, or on a digital recorder. If the 
equipment does not hold the required pressure during a test, you must 
correct the problem and retest the affected component(s).


Sec.  250.449  What additional BOP testing requirements must I meet?

    You must meet the following additional BOP testing requirements:
    (a) Use water to test a surface BOP system;
    (b) Stump test a subsea BOP system before installation. You must 
use water to conduct this test. You may use drilling fluids to conduct 
subsequent tests of a subsea BOP system;
    (c) Alternate tests between control stations and pods;
    (d) Pressure test the blind or blind-shear ram BOP during stump 
tests and at all casing points;

[[Page 64522]]

    (e) The interval between any blind or blind-shear ram BOP pressure 
tests may not exceed 30 days;
    (f) Pressure test variable bore-pipe ram BOPs against the largest 
and smallest sizes of pipe in use, excluding drill collars and bottom-
hole tools;
    (g) Pressure test affected BOP components following the 
disconnection or repair of any well-pressure containment seal in the 
wellhead or BOP stack assembly;
    (h) Function test annular and ram BOPs every 7 days between 
pressure tests;
    (i) Actuate safety valves assembled with proper casing connections 
before running casing;
    (j) Test all ROV intervention functions on your subsea BOP stack 
during the stump test. You must also test at least one set of rams 
during the initial test on the seafloor. You must submit test 
procedures with your APD or APM for District Manager approval. You 
must:
    (1) ensure that the ROV hot stabs are function tested and are 
capable of actuating, at a minimum, one set of pipe rams and one set of 
blind-shear rams and unlatching the LMRP; and
    (2) document all your test results and make them available to BSEE 
upon request;
    (k) Function test autoshear and deadman systems on your subsea BOP 
stack during the stump test. You must also test the deadman system 
during the initial test on the seafloor.
    (1) You must submit test procedures with your APD or APM for 
District Manager approval.
    (2) You must document all your test results and make them available 
to BSEE upon request.


Sec.  250.450  What are the recordkeeping requirements for BOP tests?

    You must record the time, date, and results of all pressure tests, 
actuations, and inspections of the BOP system, system components, and 
marine riser in the driller's report. In addition, you must:
    (a) Record BOP test pressures on pressure charts;
    (b) Require your onsite representative to sign and date BOP test 
charts and reports as correct;
    (c) Document the sequential order of BOP and auxiliary equipment 
testing and the pressure and duration of each test. For subsea BOP 
systems, you must also record the closing times for annular and ram 
BOPs. You may reference a BOP test plan if it is available at the 
facility;
    (d) Identify the control station and pod used during the test;
    (e) Identify any problems or irregularities observed during BOP 
system testing and record actions taken to remedy the problems or 
irregularities; and
    (f) Retain all records, including pressure charts, driller's 
report, and referenced documents pertaining to BOP tests, actuations, 
and inspections at the facility for the duration of drilling.


Sec.  250.451  What must I do in certain situations involving BOP 
equipment or systems?

    The table in this section describes actions that lessees must take 
when certain situations occur with BOP systems during drilling 
activities.

------------------------------------------------------------------------
 If you encounter the following situation:       Then you must . . .
------------------------------------------------------------------------
(a) BOP equipment does not hold the         Correct the problem and
 required pressure during a test,            retest the affected
                                             equipment.
(b) Need to repair or replace a surface or  First place the well in a
 subsea BOP system,                          safe, controlled condition
                                             (e.g., before drilling out
                                             a casing shoe or after
                                             setting a cement plug,
                                             bridge plug, or a packer).
(c) Need to postpone a BOP test due to      Record the reason for
 well-control problems such as lost          postponing the test in the
 circulation, formation fluid influx, or     driller's report and
 stuck drill pipe,                           conduct the required BOP
                                             test on the first trip out
                                             of the hole.
(d) BOP control station or pod that does    Suspend further drilling
 not function properly,                      operations until that
                                             station or pod is operable.
(e) Want to drill with a tapered drill-     Install two or more sets of
 string,                                     conventional or variable-
                                             bore pipe rams in the BOP
                                             stack to provide for the
                                             following: two sets of rams
                                             must be capable of sealing
                                             around the larger-size
                                             drill string and one set of
                                             pipe rams must be capable
                                             of sealing around the
                                             smaller-size drill string.
(f) Install casing rams in a BOP stack,     Test the ram bonnets before
                                             running casing.
(g) Want to use an annular BOP with a       Demonstrate that your well
 rated working pressure less than the        control procedures or the
 anticipated surface pressure,               anticipated well conditions
                                             will not place demands
                                             above its rated working
                                             pressure and obtain
                                             approval from the District
                                             Manager.
(h) Use a subsea BOP system in an ice-      Install the BOP stack in a
 scour area,                                 glory hole. The glory hole
                                             must be deep enough to
                                             ensure that the top of the
                                             stack is below the deepest
                                             probable ice-scour depth.
(i) You activate blind-shear rams or        Retrieve, physically
 casing shear rams during a well control     inspect, and conduct a full
 situation, in which pipe or casing is       pressure test of the BOP
 sheared,                                    stack after the situation
                                             is fully controlled.
------------------------------------------------------------------------

Drilling Fluid Requirements


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

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


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

    Your drilling fluid program must include the following safe 
practices:
    (a) Before starting out of the hole with drill pipe, you must 
properly condition the drilling fluid. You must circulate a volume of 
drilling fluid equal to the annular volume with the drill pipe just 
off-bottom. You may omit this practice if documentation in the 
driller's report shows:
    (1) No indication of formation fluid influx before starting to pull 
the drill pipe from the hole;
    (2) The weight of returning drilling fluid is within 0.2 pounds per 
gallon (1.5 pounds per cubic foot) of the drilling fluid entering the 
hole; and
    (3) Other drilling fluid properties are within the limits 
established by the program approved in the APD.
    (b) Record each time you circulate drilling fluid in the hole in 
the driller's report;
    (c) When coming out of the hole with drill pipe, you must fill the 
annulus with drilling fluid before the hydrostatic pressure decreases 
by 75 psi, or every five stands of drill pipe, whichever gives a lower 
decrease in hydrostatic pressure. You must calculate the number of 
stands of drill pipe and drill collars that you may pull before you

[[Page 64523]]

must fill the hole. You must also calculate the equivalent drilling 
fluid volume needed to fill the hole. Both sets of numbers must be 
posted near the driller's station. You must use a mechanical, 
volumetric, or electronic device to measure the drilling fluid required 
to fill the hole;
    (d) You must run and pull drill pipe and downhole tools at 
controlled rates so you do not swab or surge the well;
    (e) When there is an indication of swabbing or influx of formation 
fluids, you must take appropriate measures to control the well. You 
must circulate and condition the well, on or near-bottom, unless well 
or drilling-fluid conditions prevent running the drill pipe back to the 
bottom;
    (f) You must calculate and post near the driller's console the 
maximum pressures that you may safely contain under a shut-in BOP for 
each casing string. The pressures posted must consider the surface 
pressure at which the formation at the shoe would break down, the rated 
working pressure of the BOP stack, and 70 percent of casing burst (or 
casing test as approved by the District Manager). As a minimum, you 
must post the following two pressures:
    (1) The surface pressure at which the shoe would break down. This 
calculation must consider the current drilling fluid weight in the 
hole; and
    (2) The lesser of the BOP's rated working pressure or 70 percent of 
casing-burst pressure (or casing test otherwise approved by the 
District Manager);
    (g) You must install an operable drilling fluid-gas separator and 
degasser before you begin drilling operations. You must maintain this 
equipment throughout the drilling of the well;
    (h) Before pulling drill-stem test tools from the hole, you must 
circulate or reverse-circulate the test fluids in the hole. If 
circulating out test fluids is not feasible, you may bullhead test 
fluids out of the drill-stem test string and tools with an appropriate 
kill weight fluid;
    (i) When circulating, you must test the drilling fluid at least 
once each tour, or more frequently if conditions warrant. Your tests 
must conform to industry-accepted practices and include density, 
viscosity, and gel strength; hydrogenion concentration; filtration; and 
any other tests the District Manager requires for monitoring and 
maintaining drilling fluid quality, prevention of downhole equipment 
problems and for kick detection. You must record the results of these 
tests in the drilling fluid report;
    (j) Before displacing kill-weight drilling fluid from the wellbore, 
you must obtain prior approval from the District Manager. To obtain 
approval, you must submit with your APD or APM your reasons for 
displacing the kill-weight drilling fluid and provide detailed step-by-
step written procedures describing how you will safely displace these 
fluids. The step-by-step displacement procedures must address the 
following:
    (1) number and type of independent barriers that are in place for 
each flow path,
    (2) tests you will conduct to ensure integrity of independent 
barriers,
    (3) BOP procedures you will use while displacing kill weight 
fluids, and
    (4) procedures you will use to monitor fluids entering and leaving 
the wellbore; and
    (k) In areas where permafrost and/or hydrate zones are present or 
may be present, you must control drilling fluid temperatures to drill 
safely through those zones.


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

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


Sec.  250.458  What quantities of drilling fluids are required?

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


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

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

[[Page 64524]]

as far as practicable from hazardous areas; and
    (d) Alarms that activate when the mechanical ventilation system 
fails.

Other Drilling Requirements


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

    (a) If you intend to conduct a well test, you must include your 
projected plans for the test with your APD (form BSEE-0123) or in an 
Application for Permit to Modify (APM) (form BSEE-0124). Your plans 
must include at least the following information:
    (1) Estimated flowing and shut-in tubing pressures;
    (2) Estimated flow rates and cumulative volumes;
    (3) Time duration of flow, buildup, and drawdown periods;
    (4) Description and rating of surface and subsurface test 
equipment;
    (5) Schematic drawing, showing the layout of test equipment;
    (6) Description of safety equipment, including gas detectors and 
fire-fighting equipment;
    (7) Proposed methods to handle or transport produced fluids; and
    (8) Description of the test procedures.
    (b) You must give the District Manager at least 24-hours notice 
before starting a well test.


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

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


Sec.  250.462  What are the requirements for well-control drills?

    You must conduct a weekly well-control drill with each drilling 
crew. Your drill must familiarize the crew with its roles and functions 
so that all crew members can perform their duties promptly and 
efficiently.
    (a) Well-control drill plan. You must prepare a well control drill 
plan for each well. Your plan must outline the assignments for each 
crew member and establish times to complete each portion of the drill. 
You must post a copy of the well control drill plan on the rig floor or 
bulletin board.
    (b) Timing of drills. You must conduct each drill during a period 
of activity that minimizes the risk to drilling operations. The timing 
of your drills must cover a range of different operations, including 
drilling with a diverter, on-bottom drilling, and tripping.
    (c) Recordkeeping requirements. For each drill, you must record the 
following in the driller's report:
    (1) The time to be ready to close the diverter or BOP system; and
    (2) The total time to complete the entire drill.
    (d) BSEE ordered drill. A BSEE authorized representative may 
require you to conduct a well control drill during a BSEE inspection. 
The BSEE representative will consult with your onsite representative 
before requiring the drill.


Sec.  250.463  Who establishes field drilling rules?

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

Applying for a Permit To Modify and Well Records


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

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

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


[[Page 64525]]

    (b) If you intend to perform any of the actions specified in 
paragraph (a)(1) of this section, you must meet the following 
additional requirements:
    (1) Your APM (Form BSEE-0124) must contain a detailed statement of 
the proposed work that would materially change from the approved APD. 
The submission of your APM must be accompanied by payment of the 
service fee listed in Sec.  250.125;
    (2) Your form BSEE-0124 must include the present status of the 
well, depth of all casing strings set to date, well depth, present 
production zones and productive capability, and all other information 
specified; and
    (3) Within 30 days after completing this work, you must submit form 
BSEE-0124 with detailed information about the work to the District 
Manager, unless you have already provided sufficient information in a 
Well Activity Report, form BSEE-0133 (Sec.  250.468(b)).


Sec.  250.466  What records must I keep?

    You must keep complete, legible, and accurate records for each 
well. You must keep drilling records onsite while drilling activities 
continue. After completion of drilling activities, you must keep all 
drilling and other well records for the time periods shown in Sec.  
250.467. You may keep these records at a location of your choice. The 
records must contain complete information on all of the following:
    (a) Well operations;
    (b) Descriptions of formations penetrated;
    (c) Content and character of oil, gas, water, and other mineral 
deposits in each formation;
    (d) Kind, weight, size, grade, and setting depth of casing;
    (e) All well logs and surveys run in the wellbore;
    (f) Any significant malfunction or problem; and
    (g) All other information required by the District Manager in the 
interests of resource evaluation, waste prevention, conservation of 
natural resources, and the protection of correlative rights, safety, 
and environment.


Sec.  250.467  How long must I keep records?

    You must keep records for the time periods shown in the following 
table.

------------------------------------------------------------------------
  You must keep records relating to . . .            Until . . .
------------------------------------------------------------------------
(a) Drilling,                               Ninety days after you
                                             complete drilling
                                             operations.
(b) Casing and liner pressure tests,        Two years after the
 diverter tests, and BOP tests,              completion of drilling
                                             operations.
(c) Completion of a well or of any          You permanently plug and
 workover activity that materially alters    abandon the well or until
 the completion configuration or affects a   you forward the records
 hydrocarbon-bearing zone,                   with a lease assignment.
------------------------------------------------------------------------

Sec.  250.468  What well records am I required to submit?

    (a) You must submit copies of logs or charts of electrical, 
radioactive, sonic, and other well-logging operations; directional and 
vertical-well surveys; velocity profiles and surveys; and analysis of 
cores to BSEE. Each Region will provide specific instructions for 
submitting well logs and surveys.
    (b) For drilling operations in the GOM OCS Region, you must submit 
form BSEE-0133, Well Activity Report, to the District Manager on a 
weekly basis.
    (c) For drilling operations in the Pacific or Alaska OCS Regions, 
you must submit form BSEE-0133, Well Activity Report, to the District 
Manager on a daily basis.


Sec.  250.469  What other well records could I be required to submit?

    The District Manager or Regional Supervisor may require you to 
submit copies of any or all of the following well records.
    (a) Well records as specified in Sec.  250.466;
    (b) Paleontological interpretations or reports identifying 
microscopic fossils by depth and/or washed samples of drill cuttings 
that you normally maintain for paleontological determinations. The 
Regional Supervisor may issue a Notice to Lessees that prescribes the 
manner, timeframe, and format for submitting this information;
    (c) Service company reports on cementing, perforating, acidizing, 
testing, or other similar services; or
    (d) Other reports and records of operations.

Hydrogen Sulfide


Sec.  250.490  Hydrogen sulfide.

    (a) What precautions must I take when operating in an H2S area? You 
must:
    (1) Take all necessary and feasible precautions and measures to 
protect personnel from the toxic effects of H2S and to 
mitigate damage to property and the environment caused by 
H2S. You must follow the requirements of this section when 
conducting drilling, well-completion/well-workover, and production 
operations in zones with H2S present and when conducting 
operations in zones where the presence of H2S is unknown. 
You do not need to follow these requirements when operating in zones 
where the absence of H2S has been confirmed; and
    (2) Follow your approved contingency plan.
    (b) Definitions. Terms used in this section have the following 
meanings:
    Facility means a vessel, a structure, or an artificial island used 
for drilling, well-completion, well-workover, and/or production 
operations.
    H2S absent means:
    (1) Drilling, logging, coring, testing, or producing operations 
have confirmed the absence of H2S in concentrations that 
could potentially result in atmospheric concentrations of 20 ppm or 
more of H2S; or
    (2) Drilling in the surrounding areas and correlation of geological 
and seismic data with equivalent stratigraphic units have confirmed an 
absence of H2S throughout the area to be drilled.
    H2S present means that drilling, logging, coring, testing, or 
producing operations have confirmed the presence of H2S in 
concentrations and volumes that could potentially result in atmospheric 
concentrations of 20 ppm or more of H2S.
    H2S unknown means the designation of a zone or geologic formation 
where neither the presence nor absence of H2S has been 
confirmed.
    Well-control fluid means drilling mud and completion or workover 
fluid as appropriate to the particular operation being conducted.
    (c) Classifying an area for the presence of H2S. You must:
    (1) Request and obtain an approved classification for the area from 
the Regional Supervisor before you begin operations. Classifications 
are ``H2S absent,'' H2S present,'' or 
``H2S unknown'';
    (2) Submit your request with your application for permit to drill;
    (3) Support your request with available information such as 
geologic and geophysical data and correlations, well logs, formation 
tests, cores and analysis of formation fluids; and
    (4) Submit a request for reclassification of a zone when additional 
data indicate a different classification is needed.

[[Page 64526]]

    (d) What do I do if conditions change? If you encounter 
H2S that could potentially result in atmospheric 
concentrations of 20 ppm or more in areas not previously classified as 
having H2S present, you must immediately notify BSEE and 
begin to follow requirements for areas with H2S present.
    (e) What are the requirements for conducting simultaneous 
operations? When conducting any combination of drilling, well-
completion, well-workover, and production operations simultaneously, 
you must follow the requirements in the section applicable to each 
individual operation.
    (f) Requirements for submitting an H2S Contingency Plan. Before you 
begin operations, you must submit an H2S Contingency Plan to 
the District Manager for approval. Do not begin operations before the 
District Manager approves your plan. You must keep a copy of the 
approved plan in the field, and you must follow the plan at all times. 
Your plan must include:
    (1) Safety procedures and rules that you will follow concerning 
equipment, drills, and smoking;
    (2) Training you provide for employees, contractors, and visitors;
    (3) Job position and title of the person responsible for the 
overall safety of personnel;
    (4) Other key positions, how these positions fit into your 
organization, and what the functions, duties, and responsibilities of 
those job positions are;
    (5) Actions that you will take when the concentration of 
H2S in the atmosphere reaches 20 ppm, who will be 
responsible for those actions, and a description of the audible and 
visual alarms to be activated;
    (6) Briefing areas where personnel will assemble during an H2S 
alert. You must have at least two briefing areas on each facility and 
use the briefing area that is upwind of the H2S source at 
any given time;
    (7) Criteria you will use to decide when to evacuate the facility 
and procedures you will use to safely evacuate all personnel from the 
facility by vessel, capsule, or lifeboat. If you use helicopters during 
H2S alerts, describe the types of H2S emergencies 
during which you consider the risk of helicopter activity to be 
acceptable and the precautions you will take during the flights;
    (8) Procedures you will use to safely position all vessels 
attendant to the facility. Indicate where you will locate the vessels 
with respect to wind direction. Include the distance from the facility 
and what procedures you will use to safely relocate the vessels in an 
emergency;
    (9) How you will provide protective-breathing equipment for all 
personnel, including contractors and visitors;
    (10) The agencies and facilities you will notify in case of a 
release of H2S (that constitutes an emergency), how you will 
notify them, and their telephone numbers. Include all facilities that 
might be exposed to atmospheric concentrations of 20 ppm or more of 
H2S;
    (11) The medical personnel and facilities you will use if needed, 
their addresses, and telephone numbers;
    (12) H2S detector locations in production facilities 
producing gas containing 20 ppm or more of H2S. Include an 
``H2S Detector Location Drawing'' showing:
    (i) All vessels, flare outlets, wellheads, and other equipment 
handling production containing H2S;
    (ii) Approximate maximum concentration of H2S in the gas 
stream; and
    (iii) Location of all H2S sensors included in your 
contingency plan;
    (13) Operational conditions when you expect to flare gas containing 
H2S including the estimated maximum gas flow rate, 
H2S concentration, and duration of flaring;
    (14) Your assessment of the risks to personnel during flaring and 
what precautionary measures you will take;
    (15) Primary and alternate methods to ignite the flare and 
procedures for sustaining ignition and monitoring the status of the 
flare (i.e., ignited or extinguished);
    (16) Procedures to shut off the gas to the flare in the event the 
flare is extinguished;
    (17) Portable or fixed sulphur dioxide (SO2)-detection 
system(s) you will use to determine SO2 concentration and 
exposure hazard when H2S is burned;
    (18) Increased monitoring and warning procedures you will take when 
the SO2 concentration in the atmosphere reaches 2 ppm;
    (19) Personnel protection measures or evacuation procedures you 
will initiate when the SO2 concentration in the atmosphere 
reaches 5 ppm;
    (20) Engineering controls to protect personnel from SO2; 
and
    (21) Any special equipment, procedures, or precautions you will use 
if you conduct any combination of drilling, well-completion, well-
workover, and production operations simultaneously.
    (g) Training program: (1) When and how often do employees need to 
be trained? All operators and contract personnel must complete an 
H2S training program to meet the requirements of this 
section:
    (i) Before beginning work at the facility; and
    (ii) Each year, within 1 year after completion of the previous 
class.
    (2) What training documentation do I need? For each individual 
working on the platform, either:
    (i) You must have documentation of this training at the facility 
where the individual is employed; or
    (ii) The employee must carry a training completion card.
    (3) What training do I need to give to visitors and employees 
previously trained on another facility?
    (i) Trained employees or contractors transferred from another 
facility must attend a supplemental briefing on your H2S 
equipment and procedures before beginning duty at your facility;
    (ii) Visitors who will remain on your facility more than 24 hours 
must receive the training required for employees by paragraph (g)(4) of 
this section; and
    (iii) Visitors who will depart before spending 24 hours on the 
facility are exempt from the training required for employees, but they 
must, upon arrival, complete a briefing that includes:
    (A) Information on the location and use of an assigned respirator; 
practice in donning and adjusting the assigned respirator; information 
on the safe briefing areas, alarm system, and hazards of H2S 
and SO2; and
    (B) Instructions on their responsibilities in the event of an 
H2S release.
    (4) What training must I provide to all other employees? You must 
train all individuals on your facility on the:
    (i) Hazards of H2S and of SO2 and the 
provisions for personnel safety contained in the H2S 
Contingency Plan;
    (ii) Proper use of safety equipment which the employee may be 
required to use;
    (iii) Location of protective breathing equipment, H2S 
detectors and alarms, ventilation equipment, briefing areas, warning 
systems, evacuation procedures, and the direction of prevailing winds;
    (iv) Restrictions and corrective measures concerning beards, 
spectacles, and contact lenses in conformance with ANSI Z88.2, American 
National Standard for Respiratory Protection (as specified in Sec.  
250.198);
    (v) Basic first-aid procedures applicable to victims of 
H2S exposure. During all drills and training sessions, you 
must address procedures for rescue and first aid for H2S 
victims;
    (vi) Location of:
    (A) The first-aid kit on the facility;
    (B) Resuscitators; and

[[Page 64527]]

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

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

     (4) May I use existing signs? You may use existing signs 
containing the words ``Danger-Hydrogen Sulfide-H2S,'' 
provided the words ``Poisonous Gas. Do Not Approach if Red Flag is 
Flying'' or ``Red Lights are Flashing'' in lettering of a minimum of 7 
inches in height are displayed on a sign immediately adjacent to the 
existing sign.
    (5) What are the requirements for flashing lights or flags? You 
must activate a sufficient number of lights or hoist a sufficient 
number of flags to be visible to vessels and aircraft. Each light must 
be of sufficient intensity to be seen by approaching vessels or 
aircraft any time it is activated (day or night). Each flag must be 
red, rectangular, a minimum width of 3 feet, and a minimum height of 2 
feet.
    (6) What is an audible warning system? An audible warning system is 
a public address system or siren, horn, or other similar warning device 
with a unique sound used only for H2S.
    (7) Are there any other requirements for visual or audible warning 
devices? Yes, you must:
    (i) Illuminate all signs and flags at night and under conditions of 
poor visibility; and
    (ii) Use warning devices that are suitable for the electrical 
classification of the area.
    (8) What actions must I take when the alarms are activated? When 
the warning devices are activated, the designated responsible persons 
must inform personnel of the level of danger and issue instructions on 
the initiation of appropriate protective measures.
    (j) H2S-detection and H2S monitoring 
equipment: (1) What are the requirements for an H2S 
detection system? An H2S detection system must:
    (i) Be capable of sensing a minimum of 10 ppm of H2S in 
the atmosphere; and
    (ii) Activate audible and visual alarms when the concentration of 
H2S in the atmosphere reaches 20 ppm.
    (2) Where must I have sensors for drilling, well-completion, and 
well-workover operations? You must locate sensors at the:
    (i) Bell nipple;
    (ii) Mud-return line receiver tank (possum belly);
    (iii) Pipe-trip tank;
    (iv) Shale shaker;
    (v) Well-control fluid pit area;
    (vi) Driller's station;
    (vii) Living quarters; and
    (viii) All other areas where H2S may accumulate.
    (3) Do I need mud sensors? The District Manager may require mud 
sensors in the possum belly in cases where the ambient air sensors in 
the mud-return system do not consistently detect the presence of 
H2S.
    (4) How often must I observe the sensors? During drilling, well-
completion and well-workover operations, you must continuously observe 
the H2S levels indicated by the monitors in the work areas 
during the following operations:
    (i) When you pull a wet string of drill pipe or workover string;
    (ii) When circulating bottoms-up after a drilling break;
    (iii) During cementing operations;
    (iv) During logging operations; and
    (v) When circulating to condition mud or other well-control fluid.
    (5) Where must I have sensors for production operations? On a 
platform where gas containing H2S of 20 ppm or greater is 
produced, processed, or otherwise handled:
    (i) You must have a sensor in rooms, buildings, deck areas, or low-
laying deck areas not otherwise covered by paragraph (j)(2) of this 
section, where atmospheric concentrations of H2S could reach 
20 ppm or more. You must have at least one sensor per 400 square feet 
of deck area or fractional part of 400 square feet;
    (ii) You must have a sensor in buildings where personnel have their 
living quarters;
    (iii) You must have a sensor within 10 feet of each vessel, 
compressor, wellhead, manifold, or pump, which could release enough 
H2S to result in atmospheric concentrations of 20 ppm at a 
distance of 10 feet from the component;
    (iv) You may use one sensor to detect H2S around 
multiple pieces of equipment, provided the sensor is located no more 
than 10 feet from each piece, except that you need to use at least two 
sensors to monitor compressors exceeding 50 horsepower;
    (v) You do not need to have sensors near wells that are shut in at 
the master valve and sealed closed;
    (vi) When you determine where to place sensors, you must consider:
    (A) The location of system fittings, flanges, valves, and other 
devices subject to leaks to the atmosphere; and
    (B) Design factors, such as the type of decking and the location of 
fire walls; and
    (vii) The District Manager may require additional sensors or other 
monitoring capabilities, if warranted by site specific conditions.
    (6) How must I functionally test the H2S Detectors? (i) Personnel 
trained to calibrate the particular H2S detector equipment 
being used must test detectors by exposing them to a known 
concentration in the range of 10 to 30 ppm of H2S.
    (ii) If the results of any functional test are not within 2 ppm or 
10 percent, whichever is greater, of the applied

[[Page 64528]]

concentration, recalibrate the instrument.
    (7) How often must I test my detectors? (i) When conducting 
drilling, drill stem testing, well-completion, or well-workover 
operations in areas classified as H2S present or 
H2S unknown, test all detectors at least once every 24 
hours. When drilling, begin functional testing before the bit is 1,500 
feet (vertically) above the potential H2S zone.
    (ii) When conducting production operations, test all detectors at 
least every 14 days between tests.
    (iii) If equipment requires calibration as a result of two 
consecutive functional tests, the District Manager may require that 
H2S-detection and H2S-monitoring equipment be 
functionally tested and calibrated more frequently.
    (8) What documentation must I keep? (i) You must maintain records 
of testing and calibrations (in the drilling or production operations 
report, as applicable) at the facility to show the present status and 
history of each device, including dates and details concerning:
    (A) Installation;
    (B) Removal;
    (C) Inspection;
    (D) Repairs;
    (E) Adjustments; and
    (F) Reinstallation.
    (ii) Records must be available for inspection by BSEE personnel.
    (9) What are the requirements for nearby vessels? If vessels are 
stationed overnight alongside facilities in areas of H2S 
present or H2S unknown, you must equip vessels with an 
H2S-detection system that activates audible and visual 
alarms when the concentration of H2S in the atmosphere 
reaches 20 ppm. This requirement does not apply to vessels positioned 
upwind and at a safe distance from the facility in accordance with the 
positioning procedure described in the approved H2S 
Contingency Plan.
    (10) What are the requirements for nearby facilities? The District 
Manager may require you to equip nearby facilities with portable or 
fixed H2S detector(s) and to test and calibrate those 
detectors. To invoke this requirement, the District Manager will 
consider dispersion modeling results from a possible release to 
determine if 20 ppm H2S concentration levels could be 
exceeded at nearby facilities.
    (11) What must I do to protect against SO2 if I burn gas containing 
H2S? You must:
    (i) Monitor the SO2concentration in the air with 
portable or strategically placed fixed devices capable of detecting a 
minimum of 2 ppm of SO2;
    (ii) Take readings at least hourly and at any time personnel detect 
SO2 odor or nasal irritation;
    (iii) Implement the personnel protective measures specified in the 
H2S Contingency Plan if the SO2 concentration in 
the work area reaches 2 ppm; and
    (iv) Calibrate devices every 3 months if you use fixed or portable 
electronic sensing devices to detect SO2.
    (12) May I use alternative measures? You may follow alternative 
measures instead of those in paragraph (j)(11) of this section if you 
propose and the Regional Supervisor approves the alternative measures.
    (13) What are the requirements for protective-breathing equipment? 
In an area classified as H2S present or H2S 
unknown, you must:
    (i) Provide all personnel, including contractors and visitors on a 
facility, with immediate access to self-contained pressure-demand-type 
respirators with hoseline capability and breathing time of at least 15 
minutes.
    (ii) Design, select, use, and maintain respirators in conformance 
with ANSI Z88.2 (as specified in Sec.  250.198).
    (iii) Make available at least two voice-transmission devices, which 
can be used while wearing a respirator, for use by designated 
personnel.
    (iv) Make spectacle kits available as needed.
    (v) Store protective-breathing equipment in a location that is 
quickly and easily accessible to all personnel.
    (vi) Label all breathing-air bottles as containing breathing-
quality air for human use.
    (vii) Ensure that vessels attendant to facilities carry appropriate 
protective-breathing equipment for each crew member. The District 
Manager may require additional protective-breathing equipment on 
certain vessels attendant to the facility.
    (viii) During H2S alerts, limit helicopter flights to 
and from facilities to the conditions specified in the H2S 
Contingency Plan. During authorized flights, the flight crew and 
passengers must use pressure-demand-type respirators. You must train 
all members of flight crews in the use of the particular type(s) of 
respirator equipment made available.
    (ix) As appropriate to the particular operation(s), (production, 
drilling, well-completion or well-workover operations, or any 
combination of them), provide a system of breathing-air manifolds, 
hoses, and masks at the facility and the briefing areas. You must 
provide a cascade air-bottle system for the breathing-air manifolds to 
refill individual protective-breathing apparatus bottles. The cascade 
air-bottle system may be recharged by a high-pressure compressor 
suitable for providing breathing-quality air, provided the compressor 
suction is located in an uncontaminated atmosphere.
    (k) Personnel safety equipment: (1) What additional personnel-
safety equipment do I need? You must ensure that your facility has:
    (i) Portable H2S detectors capable of detecting a 10 ppm 
concentration of H2S in the air available for use by all 
personnel;
    (ii) Retrieval ropes with safety harnesses to retrieve 
incapacitated personnel from contaminated areas;
    (iii) Chalkboards and/or note pads for communication purposes 
located on the rig floor, shale-shaker area, the cement-pump rooms, 
well-bay areas, production processing equipment area, gas compressor 
area, and pipeline-pump area;
    (iv) Bull horns and flashing lights; and
    (v) At least three resuscitators on manned facilities, and a number 
equal to the personnel on board, not to exceed three, on normally 
unmanned facilities, complete with face masks, oxygen bottles, and 
spare oxygen bottles.
    (2) What are the requirements for ventilation equipment? You must:
    (i) Use only explosion-proof ventilation devices;
    (ii) Install ventilation devices in areas where H2S or 
SO2 may accumulate; and
    (iii) Provide movable ventilation devices in work areas. The 
movable ventilation devices must be multidirectional and capable of 
dispersing H2S or SO2 vapors away from working 
personnel.
    (3) What other personnel safety equipment do I need? You must have 
the following equipment readily available on each facility:
    (i) A first-aid kit of appropriate size and content for the number 
of personnel on the facility; and
    (ii) At least one litter or an equivalent device.
    (l) Do I need to notify BSEE in the event of an H2S release? You 
must notify BSEE without delay in the event of a gas release which 
results in a 15-minute time-weighted average atmospheric concentration 
of H2S of 20 ppm or more anywhere on the OCS facility. You 
must report these gas releases to the District Manager immediately by 
oral communication, with a written follow-up report within 15 days, 
pursuant to Sec. Sec.  250.188 through 250.190.
    (m) Do I need to use special drilling, completion and workover 
fluids or

[[Page 64529]]

procedures? When working in an area classified as H2S 
present or H2S unknown:
    (1) You may use either water- or oil-base muds in accordance with 
Sec.  250.300(b)(1).
    (2) If you use water-base well-control fluids, and if ambient air 
sensors detect H2S, you must immediately conduct either the 
Garrett-Gas-Train test or a comparable test for soluble sulfides to 
confirm the presence of H2S.
    (3) If the concentration detected by air sensors in over 20 ppm, 
personnel conducting the tests must don protective-breathing equipment 
conforming to paragraph (j)(13) of this section.
    (4) You must maintain on the facility sufficient quantities of 
additives for the control of H2S, well-control fluid pH, and 
corrosion equipment.
    (i) Scavengers. You must have scavengers for control of 
H2S available on the facility. When H2S is 
detected, you must add scavengers as needed. You must suspend drilling 
until the scavenger is circulated throughout the system.
    (ii) Control pH. You must add additives for the control of pH to 
water-base well-control fluids in sufficient quantities to maintain pH 
of at least 10.0.
    (iii) Corrosion inhibitors. You must add additives to the well-
control fluid system as needed for the control of corrosion.
    (5) You must degas well-control fluids containing H2S at 
the optimum location for the particular facility. You must collect the 
gases removed and burn them in a closed flare system conforming to 
paragraph (q)(6) of this section.
    (n) What must I do in the event of a kick? In the event of a kick, 
you must use one of the following alternatives to dispose of the well-
influx fluids giving consideration to personnel safety, possible 
environmental damage, and possible facility well-equipment damage:
    (1) Contain the well-fluid influx by shutting in the well and 
pumping the fluids back into the formation.
    (2) Control the kick by using appropriate well-control techniques 
to prevent formation fracturing in an open hole within the pressure 
limits of the well equipment (drill pipe, work string, casing, 
wellhead, BOP system, and related equipment). The disposal of 
H2S and other gases must be through pressurized or 
atmospheric mud-separator equipment depending on volume, pressure and 
concentration of H2S. The equipment must be designed to 
recover well-control fluids and burn the gases separated from the well-
control fluid. The well-control fluid must be treated to neutralize 
H2S and restore and maintain the proper quality.
    (o) Well testing in a zone known to contain H2S. When testing a 
well in a zone with H2S present, you must do all of the 
following:
    (1) Before starting a well test, conduct safety meetings for all 
personnel who will be on the facility during the test. At the meetings, 
emphasize the use of protective-breathing equipment, first-aid 
procedures, and the Contingency Plan. Only competent personnel who are 
trained and are knowledgeable of the hazardous effects of 
H2S must be engaged in these tests.
    (2) Perform well testing with the minimum number of personnel in 
the immediate vicinity of the rig floor and with the appropriate test 
equipment to safely and adequately perform the test. During the test, 
you must continuously monitor H2S levels.
    (3) Not burn produced gases except through a flare which meets the 
requirements of paragraph (q)(6) of this section. Before flaring gas 
containing H2S, you must activate SO2 monitoring 
equipment in accordance with paragraph (j)(11) of this section. If you 
detect SO2 in excess of 2 ppm, you must implement the 
personnel protective measures in your H2S Contingency Plan, 
required by paragraph (f) of this section. You must also follow the 
requirements of Sec.  250.1164. You must pipe gases from stored test 
fluids into the flare outlet and burn them.
    (4) Use downhole test tools and wellhead equipment suitable for 
H2S service.
    (5) Use tubulars suitable for H2S service. You must not 
use drill pipe for well testing without the prior approval of the 
District Manager. Water cushions must be thoroughly inhibited in order 
to prevent H2S attack on metals. You must flush the test 
string fluid treated for this purpose after completion of the test.
    (6) Use surface test units and related equipment that is designed 
for H2S service.
    (p) Metallurgical properties of equipment. When operating in a zone 
with H2S present, you must use equipment that is constructed 
of materials with metallurgical properties that resist or prevent 
sulfide stress cracking (also known as hydrogen embrittlement, stress 
corrosion cracking, or H2S embrittlement), chloride-stress 
cracking, hydrogen-induced cracking, and other failure modes. You must 
do all of the following:
    (1) Use tubulars and other equipment, casing, tubing, drill pipe, 
couplings, flanges, and related equipment that is designed for 
H2S service.
    (2) Use BOP system components, wellhead, pressure-control 
equipment, and related equipment exposed to H2S-bearing 
fluids in conformance with NACE Standard MR0175-03 (as specified in 
Sec.  250.198).
    (3) Use temporary downhole well-security devices such as 
retrievable packers and bridge plugs that are designed for 
H2S service.
    (4) When producing in zones bearing H2S, use equipment 
constructed of materials capable of resisting or preventing sulfide 
stress cracking.
    (5) Keep the use of welding to a minimum during the installation or 
modification of a production facility. Welding must be done in a manner 
that ensures resistance to sulfide stress cracking.
    (q) General requirements when operating in an H2S zone: (1) Coring 
operations. When you conduct coring operations in H2S-
bearing zones, all personnel in the working area must wear protective-
breathing equipment at least 10 stands in advance of retrieving the 
core barrel. Cores to be transported must be sealed and marked for the 
presence of H2S.
    (2) Logging operations. You must treat and condition well-control 
fluid in use for logging operations to minimize the effects of 
H2S on the logging equipment.
    (3) Stripping operations. Personnel must monitor displaced well-
control fluid returns and wear protective-breathing equipment in the 
working area when the atmospheric concentration of H2S 
reaches 20 ppm or if the well is under pressure.
    (4) Gas-cut well-control fluid or well kick from H2S-bearing zone. 
If you decide to circulate out a kick, personnel in the working area 
during bottoms-up and extended-kill operations must wear protective-
breathing equipment.
    (5) Drill- and workover-string design and precautions. Drill- and 
workover-strings must be designed consistent with the anticipated 
depth, conditions of the hole, and reservoir environment to be 
encountered. You must minimize exposure of the drill- or workover-
string to high stresses as much as practical and consistent with well 
conditions. Proper handling techniques must be taken to minimize 
notching and stress concentrations. Precautions must be taken to 
minimize stresses caused by doglegs, improper stiffness ratios, 
improper torque, whip, abrasive wear on tool joints, and joint 
imbalance.
    (6) Flare system. The flare outlet must be of a diameter that 
allows easy nonrestricted flow of gas. You must locate flare line 
outlets on the downside

[[Page 64530]]

of the facility and as far from the facility as is feasible, taking 
into account the prevailing wind directions, the wake effects caused by 
the facility and adjacent structure(s), and the height of all such 
facilities and structures. You must equip the flare outlet with an 
automatic ignition system including a pilot-light gas source or an 
equivalent system. You must have alternate methods for igniting the 
flare. You must pipe to the flare system used for H2S all 
vents from production process equipment, tanks, relief valves, burst 
plates, and similar devices.
    (7) Corrosion mitigation. You must use effective means of 
monitoring and controlling corrosion caused by acid gases 
(H2S and CO2) in both the downhole and surface 
portions of a production system. You must take specific corrosion 
monitoring and mitigating measures in areas of unusually severe 
corrosion where accumulation of water and/or higher concentration of 
H2S exists.
    (8) Wireline lubricators. Lubricators which may be exposed to 
fluids containing H2S must be of H2S-resistant 
materials.
    (9) Fuel and/or instrument gas. You must not use gas containing 
H2S for instrument gas. You must not use gas containing 
H2S for fuel gas without the prior approval of the District 
Manager.
    (10) Sensing lines and devices. Metals used for sensing line and 
safety-control devices which are necessarily exposed to H2S-
bearing fluids must be constructed of H2S-corrosion 
resistant materials or coated so as to resist H2S corrosion.
    (11) Elastomer seals. You must use H2S-resistant 
materials for all seals which may be exposed to fluids containing 
H2S.
    (12) Water disposal. If you dispose of produced water by means 
other than subsurface injection, you must submit to the District 
Manager an analysis of the anticipated H2S content of the 
water at the final treatment vessel and at the discharge point. The 
District Manager may require that the water be treated for removal of 
H2S. The District Manager may require the submittal of an 
updated analysis if the water disposal rate or the potential 
H2S content increases.
    (13) Deck drains. You must equip open deck drains with traps or 
similar devices to prevent the escape of H2S gas into the 
atmosphere.
    (14) Sealed voids. You must take precautions to eliminate sealed 
spaces in piping designs (e.g., slip-on flanges, reinforcing pads) 
which can be invaded by atomic hydrogen when H2S is present.

Subpart E--Oil and Gas Well-Completion Operations


Sec.  250.500  General requirements.

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


Sec.  250.501  Definition.

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


Sec.  250.502  Equipment movement.

    The movement of well-completion rigs and related equipment on and 
off a platform or from well to well on the same platform, including 
rigging up and rigging down, shall be conducted in a safe manner. All 
wells in the same well-bay which are capable of producing hydrocarbons 
shall be shut in below the surface with a pump-through-type tubing plug 
and at the surface with a closed master valve prior to moving well-
completion rigs and related equipment, unless otherwise approved by the 
District Manager. A closed surface-controlled subsurface safety valve 
of the pump-through type may be used in lieu of the pump-through-type 
tubing plug, provided that the surface control has been locked out of 
operation. The well from which the rig or related equipment is to be 
moved shall also be equipped with a back-pressure valve prior to 
removing the blowout preventer (BOP) system and installing the tree.


Sec.  250.503  Emergency shutdown system.

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


Sec.  250.504  Hydrogen sulfide.

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


Sec.  250.505  Subsea completions.

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


Sec.  250.506  Crew instructions.

    Prior to engaging in well-completion operations, crew members shall 
be instructed in the safety requirements of the operations to be 
performed, possible hazards to be encountered, and general safety 
considerations to protect personnel, equipment, and the environment. 
Date and time of safety meetings shall be recorded and available at the 
facility for review by BSEE representatives.


Sec.  250.507  [Reserved]


Sec.  250.508  [Reserved]


Sec.  250.509  Well-completion structures on fixed platforms.

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


Sec.  250.510  Diesel engine air intakes.

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

[[Page 64531]]

Sec.  250.511  Traveling-block safety device.

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


Sec.  250.512  Field well-completion rules.

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


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

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


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

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


Sec.  250.515  Blowout prevention equipment.

    (a) The BOP system and system components and related well-control 
equipment shall be designed, used, maintained, and tested in a manner 
necessary to assure well control in foreseeable conditions and 
circumstances, including subfreezing conditions. The working pressure 
rating of the BOP system and BOP system components shall exceed the 
expected surface pressure to which they may be subjected. If the 
expected surface pressure exceeds the rated working pressure of the 
annular preventer, the lessee shall submit with Form BSEE-0124 or Form 
BSEE-0123, as appropriate, a well-control procedure that indicates how 
the annular preventer will be utilized, and the pressure limitations 
that will be applied during each mode of pressure control.
    (b) The minimum BOP system for well-completion operations must meet 
the appropriate standards from the following table:

------------------------------------------------------------------------
                                             The minimum BOP stack must
                When . . .                          include . . .
------------------------------------------------------------------------
(1) The expected pressure is less than      Three BOPs consisting of an
 5,000 psi,                                  annular, one set of pipe
                                             rams, and one set of blind-
                                             shear rams.
(2) The expected pressure is 5,000 psi or   Four BOPs consisting of an
 greater or you use multiple tubing          annular, two sets of pipe
 strings,                                    rams, and one set of blind-
                                             shear rams.
(3) You handle multiple tubing strings      Four BOPs consisting of an
 simultaneously,                             annular, one set of pipe
                                             rams, one set of dual pipe
                                             rams, and one set of blind-
                                             shear rams.
(4) You use a tapered drill string,         At least one set of pipe
                                             rams that are capable of
                                             sealing around each size of
                                             drill string. If the
                                             expected pressure is
                                             greater than 5,000 psi,
                                             then you must have at least
                                             two sets of pipe rams that
                                             are capable of sealing
                                             around the larger size
                                             drill string. You may
                                             substitute one set of
                                             variable bore rams for two
                                             sets of pipe rams.
(5) You use a subsea BOP stack,             The requirements in Sec.
                                             250.442(a) of this part.
------------------------------------------------------------------------


[[Page 64532]]

     (c) The BOP systems for well completions must be equipped with the 
following:
    (1) A hydraulic-actuating system that provides sufficient 
accumulator capacity to supply 1.5 times the volume necessary to close 
all BOP equipment units with a minimum pressure of 200 psi above the 
precharge pressure without assistance from a charging system. 
Accumulator regulators supplied by rig air and without a secondary 
source of pneumatic supply, must be equipped with manual overrides, or 
alternately, other devices provided to ensure capability of hydraulic 
operations if rig air is lost.
    (2) A secondary power source, independent from the primary power 
source, with sufficient capacity to close all BOP system components and 
hold them closed.
    (3) Locking devices for the pipe-ram preventers.
    (4) At least one remote BOP-control station and one BOP-control 
station on the rig floor.
    (5) A choke line and a kill line each equipped with two full 
opening valves and a choke manifold. At least one of the valves on the 
choke line shall be remotely controlled. At least one of the valves on 
the kill line shall be remotely controlled, except that a check valve 
on the kill line in lieu of the remotely controlled valve may be 
installed provided that two readily accessible manual valves are in 
place and the check valve is placed between the manual valves and the 
pump. This equipment shall have a pressure rating at least equivalent 
to the ram preventers.
    (d) An inside BOP or a spring-loaded, back-pressure safety valve 
and an essentially full-opening, work-string safety valve in the open 
position shall be maintained on the rig floor at all times during well-
completion operations. A wrench to fit the work-string safety valve 
shall be readily available. Proper connections shall be readily 
available for inserting valves in the work string.
    (e) The subsea BOP system for well-completions must meet the 
requirements in Sec.  250.442 of this part.


Sec.  250.516  Blowout preventer system tests, inspections, and 
maintenance.

    (a) BOP pressure testing timeframes. You must pressure test your 
BOP system:
    (1) When installed; and
    (2) Before 14 days have elapsed since your last BOP pressure test. 
You must begin to test your BOP system before 12 a.m. (midnight) on the 
14th day following the conclusion of the previous test. However, the 
District Manager may require testing every 7 days if conditions or BOP 
performance warrant.
    (b) BOP test pressures. When you test the BOP system, you must 
conduct a low pressure and a high pressure test for each BOP component. 
Each individual pressure test must hold pressure long enough to 
demonstrate that the tested component(s) holds the required pressure. 
The District Manager may approve or require other test pressures or 
practices. Required test pressures are as follows:
    (1) All low pressure tests must be between 200 and 300 psi. Any 
initial pressure above 300 psi must be bled back to a pressure between 
200 and 300 psi before starting the test. If the initial pressure 
exceeds 500 psi, you must bleed back to zero and reinitiate the test. 
You must conduct the low pressure test before the high pressure test.
    (2) For ram-type BOP's, choke manifold, and other BOP equipment, 
the high pressure test must equal the rated working pressure of the 
equipment.
    (3) For annular-type BOP's, the high pressure test must equal 70 
percent of the rated working pressure of the equipment.
    (c) Duration of pressure test. Each test must hold the required 
pressure for 5 minutes.
    (1) For surface BOP systems and surface equipment of a subsea BOP 
system, a 3-minute test duration is acceptable if you record your test 
pressures on the outermost half of a 4-hour chart, on a 1-hour chart, 
or on a digital recorder.
    (2) If the equipment does not hold the required pressure during a 
test, you must remedy the problem and retest the affected component(s).
    (d) Additional BOP testing requirements. You must:
    (1) Use water to test the surface BOP system;
    (2) Stump test a subsurface BOP system before installation. You 
must use water to stump test a subsea BOP system. You may use drilling 
or completion fluids to conduct subsequent tests of a subsea BOP 
system;
    (3) Alternate tests between control stations and pods. If a control 
station or pod is not functional, you must suspend further completion 
operations until that station or pod is operable;
    (4) Pressure test the blind or blind-shear ram at least every 30 
days;
    (5) Function test annulars and rams every 7 days;
    (6) Pressure-test variable bore-pipe rams against all sizes of pipe 
in use, excluding drill collars and bottom-hole tools;
    (7) Test affected BOP components following the disconnection or 
repair of any well-pressure containment seal in the wellhead or BOP 
stack assembly;
    (8) Test all ROV intervention functions on your subsea BOP stack 
during the stump test. You must also test at least one set of rams 
during the initial test on the seafloor. You must submit test 
procedures with your APM for District Manager approval. You must:
    (i) Ensure that the ROV hot stabs are function tested and are 
capable of actuating, at a minimum, one set of pipe rams and one set of 
blind-shear rams and unlatching the LMRP;
    (ii) Document all your test results and make them available to BSEE 
upon request; and
    (9) Function test autoshear and deadman systems on your subsea BOP 
stack during the stump test. You must also test the deadman system 
during the initial test on the seafloor.
    (i) You must submit test procedures with your APM for District 
Manager approval.
    (ii) You must document all your test results and make them 
available to BSEE upon request.
    (e) Postponing BOP tests. You may postpone a BOP test if you have 
well-control problems. You must conduct the required BOP test as soon 
as possible (i.e., first trip out of the hole) after the problem has 
been remedied. You must record the reason for postponing any test in 
the driller's report.
    (f) Weekly crew drills. You must conduct a weekly drill to 
familiarize all personnel engaged in well-completion operations with 
appropriate safety measures.
    (g) BOP inspections. (1) You must inspect your BOP system to ensure 
that the equipment functions properly. The BOP inspections must meet or 
exceed the provisions of Sections 17.10 and 18.10, Inspections, 
described in API RP 53, Recommended Practices for Blowout Prevention 
Equipment Systems for Drilling Wells (as incorporated by reference in 
Sec.  250.198). You must document the procedures used, record the 
results, and make them available to BSEE upon request. You must 
maintain your records on the rig for 2 years or from the date of your 
last major inspection, whichever is longer.
    (2) You must visually inspect your BOP system and marine riser at 
least once each day if weather and sea conditions permit. You may use 
television cameras to inspect this equipment. The District Manager may 
approve alternate methods and frequencies to inspect a marine riser.

[[Page 64533]]

    (h) BOP maintenance. You must maintain your BOP system to ensure 
that the equipment functions properly. The BOP maintenance must meet or 
exceed the provisions of Sections 17.11 and 18.11, Maintenance; and 
Sections 17.12 and 18.12, Quality Management, described in API RP 53, 
Recommended Practices for Blowout Prevention Equipment Systems for 
Drilling Wells (as incorporated by reference in Sec.  250.198). You 
must document the procedures used, record the results, and make 
available to BSEE upon request. You must maintain your records on the 
rig for 2 years or from the date of your last major inspection, 
whichever is longer.
    (i) BOP test records. You must record the time, date, and results 
of all pressure tests, actuations, crew drills, and inspections of the 
BOP system, system components, and marine riser in the driller's 
report. In addition, you must:
    (1) Record BOP test pressures on pressure charts;
    (2) Have your onsite representative certify (sign and date) BOP 
test charts and reports as correct;
    (3) Document the sequential order of BOP and auxiliary equipment 
testing and the pressure and duration of each test. You may reference a 
BOP test plan if it is available at the facility;
    (4) Identify the control station or pod used during the test;
    (5) Identify any problems or irregularities observed during BOP 
system and equipment testing and record actions taken to remedy the 
problems or irregularities;
    (6) Retain all records including pressure charts, driller's report, 
and referenced documents pertaining to BOP tests, actuations, and 
inspections at the facility for the duration of the completion 
activity; and
    (7) After completion of the well, you must retain all the records 
listed in paragraph (i)(6) of this section for a period of 2 years at 
the facility, at the lessee's field office nearest the OCS facility, or 
at another location conveniently available to the District Manager.
    (j) Alternate methods. The District Manager may require, or 
approve, more frequent testing, as well as different test pressures and 
inspection methods, or other practices.


Sec.  250.517  Tubing and wellhead equipment.

    (a) No tubing string shall be placed in service or continue to be 
used unless such tubing string has the necessary strength and pressure 
integrity and is otherwise suitable for its intended use.
    (b) In the event of prolonged operations such as milling, fishing, 
jarring, or washing over that could damage the casing, the casing shall 
be pressure-tested, calipered, or otherwise evaluated every 30 days and 
the results submitted to the District Manager.
    (c) When the tree is installed, you must equip wells to monitor for 
casing pressure according to the following chart:

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

    (d) Wellhead, tree, and related equipment shall have a pressure 
rating greater than the shut-in tubing pressure and shall be designed, 
installed, used, maintained, and tested so as to achieve and maintain 
pressure control. New wells completed as flowing or gas-lift wells 
shall be equipped with a minimum of one master valve and one surface 
safety valve, installed above the master valve, in the vertical run of 
the tree.
    (e) Subsurface safety equipment shall be installed, maintained, and 
tested in compliance with Sec.  250.801 of this part.

Casing Pressure Management


Sec.  250.518  What are the requirements for casing pressure 
management?

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


Sec.  250.519  How often do I have to monitor for casing pressure?

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

----------------------------------------------------------------------------------------------------------------
                                                                                with a minimum one pressure data
               If you have . . .                    you must monitor . . .          point recorded per . . .
----------------------------------------------------------------------------------------------------------------
(a) fixed platform wells,                       monthly,                       month for each casing.
(b) subsea wells,                               continuously,                  day for the production casing.
(c) hybrid wells,                               continuously,                  day for each riser and/or the
                                                                                production casing.
(d) wells operating under a casing pressure     daily,                         day for each casing.
 request on a manned fixed platform,
(e) wells operating under a casing pressure     weekly,                        week for each casing.
 request on an unmanned fixed platform,
----------------------------------------------------------------------------------------------------------------

Sec.  250.520  When do I have to perform a casing diagnostic test?

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

[[Page 64534]]



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

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


Sec.  250.521  How do I manage the thermal effects caused by initial 
production on a newly completed or recompleted well?

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


Sec.  250.522  When do I have to repeat casing diagnostic testing?

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

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

Sec.  250.523  How long do I keep records of casing pressure and 
diagnostic tests?

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


Sec.  250.524  When am I required to take action from my casing 
diagnostic test?

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


Sec.  250.525  What do I submit if my casing diagnostic test requires 
action?

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

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

Sec.  250.526  What must I include in my notification of corrective 
action?

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


Sec.  250.527  What must I include in my casing pressure request?

    The following information must be included in the casing pressure 
request:
    (a) API number;
    (b) Lease number;

[[Page 64535]]

    (c) Area name and OCS block number;
    (d) Well number;
    (e) Company name and mailing address;
    (f) All casing, riser, and tubing sizes, weights, grades, and MIYP;
    (g) All casing/riser calculated MAWOPs;
    (h) All casing/riser pre-bleed down pressures;
    (i) Shut-in tubing pressure;
    (j) Flowing tubing pressure;
    (k) Date and the calculated daily production rate during last well 
test (oil, gas, basic sediment, and water);
    (l) Well status (shut-in, temporarily abandoned, producing, 
injecting, or gas lift);
    (m) Well type (dry tree, hybrid, or subsea);
    (n) Date of diagnostic test;
    (o) Well schematic;
    (p) Water depth;
    (q) Volumes and types of fluid bled from each casing or riser 
evaluated;
    (r) Type of diagnostic test performed:
    (1) Bleed down/buildup test;
    (2) Shut-in the well and monitor the pressure drop test;
    (3) Constant production rate and decrease the annular pressure 
test;
    (4) Constant production rate and increase the annular pressure 
test;
    (5) Change the production rate and monitor the casing pressure 
test; and
    (6) Casing pressure and tubing pressure history plot;
    (s) The casing diagnostic test data for all casing exceeding 100 
psig;
    (t) Associated shoe strengths for casing shoes exposed to annular 
fluids;
    (u) Concentration of any H2S that may be present;
    (v) Whether the structure on which the well is located is manned or 
unmanned;
    (w) Additional comments; and
    (x) Request date.


Sec.  250.528  What are the terms of my casing pressure request?

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


Sec.  250.529  What if my casing pressure request is denied?

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


Sec.  250.530  When does my casing pressure request approval become 
invalid?

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

Subpart F--Oil and Gas Well-Workover Operations


Sec.  250.600  General requirements.

    Well-workover operations shall be conducted in a manner to protect 
against harm or damage to life (including fish and other aquatic life), 
property, natural resources of the Outer Continental Shelf (OCS) 
including any mineral deposits (in areas leased and not leased), the 
National security or defense, or the marine, coastal, or human 
environment.


Sec.  250.601  Definitions.

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


Sec.  250.602  Equipment movement.

    The movement of well-workover rigs and related equipment on and off 
a platform or from well to well on the same platform, including rigging 
up and rigging down, shall be conducted in a safe manner. All wells in 
the same well-bay which are capable of producing hydrocarbons shall be 
shut in below the surface with a pump-through-type tubing plug and at 
the surface with a closed master valve prior to moving well-workover 
rigs and related equipment unless otherwise approved by the District 
Manager. A closed surface-controlled subsurface safety valve of the 
pump-through-type may be used in lieu of the pump-through-type tubing 
plug provided that the surface control has been locked out of 
operation. The well to which a well-workover rig or related equipment 
is to be moved shall also be equipped with a back-pressure valve prior 
to removing the tree and installing and testing the blowout-preventer 
(BOP) system. The well from which a well-workover rig or related 
equipment is to be moved shall also be equipped with a back pressure 
valve prior to removing the BOP system and installing the tree. Coiled 
tubing units, snubbing units, or wireline units may be moved onto a 
platform without shutting in wells.


Sec.  250.603  Emergency shutdown system.

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


Sec.  250.604  Hydrogen sulfide.

    When a well-workover operation is conducted in zones known to 
contain hydrogen sulfide (H2S) or in zones where the 
presence of H2S is unknown (as defined in Sec.  250.490 of 
this part), the lessee shall take appropriate precautions

[[Page 64536]]

to protect life and property on the platform or rig, including but not 
limited to operations such as blowing the well down, dismantling 
wellhead equipment and flow lines, circulating the well, swabbing, and 
pulling tubing, pumps and packers. The lessee shall comply with the 
requirements in Sec.  250.490 of this part as well as the appropriate 
requirements of this subpart.


Sec.  250.605  Subsea workovers.

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


Sec.  250.606  Crew instructions.

    Prior to engaging in well-workover operations, crew members shall 
be instructed in the safety requirements of the operations to be 
performed, possible hazards to be encountered, and general safety 
considerations to protect personnel, equipment, and the environment. 
Date and time of safety meetings shall be recorded and available at the 
facility for review by a BSEE representative.


Sec.  250.607  [Reserved]


Sec.  250.608  [Reserved]


Sec.  250.609  Well-workover structures on fixed platforms.

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


Sec.  250.610  Diesel engine air intakes.

    No later than May 31, 1989, diesel engine air intakes shall be 
equipped with a device to shut down the diesel engine in the event of 
runaway. Diesel engines which are continuously attended shall be 
equipped with either remote operated manual or automatic shutdown 
devices. Diesel engines which are not continuously attended shall be 
equipped with automatic shutdown devices.


Sec.  250.611  Traveling-block safety device.

    After May 31, 1989, all units being used for well-workover 
operations which have both a traveling block and a crown block shall be 
equipped with a safety device which is designed to prevent the 
traveling block from striking the crown block. The device shall be 
checked for proper operation weekly and after each drill-line slipping 
operation. The results of the operational check shall be entered in the 
operations log.


Sec.  250.612  Field well-workover rules.

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


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

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


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

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

[[Page 64537]]

gains and losses. This indicator shall include both a visual and an 
audible warning device.


Sec.  250.615  Blowout prevention equipment.

    (a) The BOP system, system components and related well-control 
equipment shall be designed, used, maintained, and tested in a manner 
necessary to assure well control in foreseeable conditions and 
circumstances, including subfreezing conditions. The working pressure 
rating of the BOP system and system components shall exceed the 
expected surface pressure to which they may be subjected. If the 
expected surface pressure exceeds the rated working pressure of the 
annular preventer, the lessee shall submit with Form BSEE-0124, 
requesting approval of the well-workover operation, a well-control 
procedure that indicates how the annular preventer will be utilized, 
and the pressure limitations that will be applied during each mode of 
pressure control.
    (b) The minimum BOP system for well-workover operations with the 
tree removed must meet the appropriate standards from the following 
table:

------------------------------------------------------------------------
                                             The minimum BOP stack must
                When . . .                          include . . .
------------------------------------------------------------------------
(1) The expected pressure is less than      Three BOPs consisting of an
 5,000 psi,                                  annular, one set of pipe
                                             rams, and one set of blind-
                                             shear rams.
(2) The expected pressure is 5,000 psi or   Four BOPs consisting of an
 greater or you use multiple tubing          annular, two sets of pipe
 strings,                                    rams, and one set of blind-
                                             shear rams.
(3) You handle multiple tubing strings      Four BOPs consisting of an
 simultaneously,                             annular, one set of pipe
                                             rams, one set of dual pipe
                                             rams, and one set of blind-
                                             shear rams.
(4) You use a tapered drill string,         At least one set of pipe
                                             rams that are capable of
                                             sealing around each size of
                                             drill string. If the
                                             expected pressure is
                                             greater than 5,000 psi,
                                             then you must have at least
                                             two sets of pipe rams that
                                             are capable of sealing
                                             around the larger size
                                             drill string. You may
                                             substitute one set of
                                             variable bore rams for two
                                             sets of pipe rams.
(5) You use a subsea BOP stack,             The requirements in Sec.
                                             250.442(a) of this part.
------------------------------------------------------------------------

     (c) The BOP systems for well-workover operations with the tree 
removed must be equipped with the following:
    (1) A hydraulic-actuating system that provides sufficient 
accumulator capacity to supply 1.5 times the volume necessary to close 
all BOP equipment units with a minimum pressure of 200 psi above the 
precharge pressure without assistance from a charging system. 
Accumulator regulators supplied by rig air and without a secondary 
source of pneumatic supply, must be equipped with manual overrides, or 
alternately, other devices provided to ensure capability of hydraulic 
operations if rig air is lost;
    (2) A secondary power source, independent from the primary power 
source, with sufficient capacity to close all BOP system components and 
hold them closed;
    (3) Locking devices for the pipe-ram preventers;
    (4) At least one remote BOP-control station and one BOP-control 
station on the rig floor; and
    (5) A choke line and a kill line each equipped with two full 
opening valves and a choke manifold. At least one of the valves on the 
choke-line shall be remotely controlled. At least one of the valves on 
the kill line shall be remotely controlled, except that a check valve 
on the kill line in lieu of the remotely controlled valve may be 
installed provided two readily accessible manual valves are in place 
and the check valve is placed between the manual valves and the pump. 
This equipment shall have a pressure rating at least equivalent to the 
ram preventers.
    (d) The minimum BOP-system components for well-workover operations 
with the tree in place and performed through the wellhead inside of 
conventional tubing using small-diameter jointed pipe (usually \3/4\ 
inch to 1\1/4\ inch) as a work string, i.e., small-tubing operations, 
shall include the following:
    (1) Two sets of pipe rams, and
    (2) One set of blind rams.
    (e) The subsea BOP system for well-workover operations must meet 
the requirements in Sec.  250.442 of this part.
    (f) For coiled tubing operations with the production tree in place, 
you must meet the following minimum requirements for the BOP system:
    (1) BOP system components must be in the following order from the 
top down:

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


[[Page 64538]]

     (2) You may use a set of hydraulically-operated combination rams 
for the blind rams and shear rams.
    (3) You may use a set of hydraulically-operated combination rams 
for the hydraulic two-way slip rams and the hydraulically-operated pipe 
rams.
    (4) You must attach a dual check valve assembly to the coiled 
tubing connector at the downhole end of the coiled tubing string for 
all coiled tubing well-workover operations. If you plan to conduct 
operations without downhole check valves, you must describe alternate 
procedures and equipment in Form BSEE-0124, Application for Permit to 
Modify and have it approved by the District Manager.
    (5) You must have a kill line and a separate choke line. You must 
equip each line with two full-opening valves and at least one of the 
valves must be remotely controlled. You may use a manual valve instead 
of the remotely controlled valve on the kill line if you install a 
check valve between the two full-opening manual valves and the pump or 
manifold. The valves must have a working pressure rating equal to or 
greater than the working pressure rating of the connection to which 
they are attached, and you must install them between the well control 
stack and the choke or kill line. For operations with expected surface 
pressures greater than 3,500 psi, the kill line must be connected to a 
pump or manifold. You must not use the kill line inlet on the BOP stack 
for taking fluid returns from the wellbore.
    (6) You must have a hydraulic-actuating system that provides 
sufficient accumulator capacity to close-open-close each component in 
the BOP stack. This cycle must be completed with at least 200 psi above 
the pre-charge pressure, without assistance from a charging system.
    (7) All connections used in the surface BOP system from the tree to 
the uppermost required ram must be flanged, including the connections 
between the well control stack and the first full-opening valve on the 
choke line and the kill line.
    (g) The minimum BOP-system components for well-workover operations 
with the tree in place and performed by moving tubing or drill pipe in 
or out of a well under pressure utilizing equipment specifically 
designed for that purpose, i.e., snubbing operations, shall include the 
following:
    (1) One set of pipe rams hydraulically operated, and
    (2) Two sets of stripper-type pipe rams hydraulically operated with 
spacer spool.
    (h) An inside BOP or a spring-loaded, back-pressure safety valve 
and an essentially full-opening, work-string safety valve in the open 
position shall be maintained on the rig floor at all times during well-
workover operations when the tree is removed or during well-workover 
operations with the tree installed and using small tubing as the work 
string. A wrench to fit the work-string safety valve shall be readily 
available. Proper connections shall be readily available for inserting 
valves in the work string. The full-opening safety valve is not 
required for coiled tubing or snubbing operations.


Sec.  250.616  Blowout preventer system testing, records, and drills.

    (a) BOP pressure tests. When you pressure test the BOP system you 
must conduct a low-pressure test and a high-pressure test for each 
component. You must conduct the low-pressure test before the high-
pressure test. For purposes of this section, BOP system components 
include ram-type BOP's, related control equipment, choke and kill 
lines, and valves, manifolds, strippers, and safety valves. Surface BOP 
systems must be pressure tested with water.
    (1) Low pressure tests. All BOP system components must be 
successfully tested to a low pressure between 200 and 300 psi. Any 
initial pressure equal to or greater than 300 psi must be bled back to 
a pressure between 200 and 300 psi before starting the test. If the 
initial pressure exceeds 500 psi, you must bleed back to zero before 
starting the test.
    (2) High pressure tests. All BOP system components must be 
successfully tested to the rated working pressure of the BOP equipment, 
or as otherwise approved by the District Manager. The annular-type BOP 
must be successfully tested at 70 percent of its rated working pressure 
or as otherwise approved by the District Manager.
    (3) Other testing requirements. Variable bore pipe rams must be 
pressure tested against the largest and smallest sizes of tubulars in 
use (jointed pipe, seamless pipe) in the well.
    (b) Times. The BOP systems shall be tested at the following times:
    (1) When installed;
    (2) At least every 7 days, alternating between control stations and 
at staggered intervals to allow each crew to operate the equipment. If 
either control system is not functional, further operations shall be 
suspended until the nonfunctional, system is operable. The test every 7 
days is not required for blind or blind-shear rams. The blind or blind-
shear rams shall be tested at least once every 30 days during 
operation. A longer period between blowout preventer tests is allowed 
when there is a stuck pipe or pressure-control operation and remedial 
efforts are being performed. The tests shall be conducted as soon as 
possible and before normal operations resume. The reason for postponing 
testing shall be entered into the operations log.
    (3) Following repairs that require disconnecting a pressure seal in 
the assembly, the affected seal will be pressure tested.
    (c) Drills. All personnel engaged in well-workover operations shall 
participate in a weekly BOP drill to familiarize crew members with 
appropriate safety measures.
    (d) Stump tests. You may conduct a stump test for the BOP system on 
location. A plan describing the stump test procedures must be included 
in your Form BSEE-0124, Application for Permit to Modify, and must be 
approved by the District Manager.
    (e) Coiled tubing tests. You must test the coiled tubing connector 
to a low pressure of 200 to 300 psi, followed by a high pressure test 
to the rated working pressure of the connector or the expected surface 
pressure, whichever is less. You must successfully pressure test the 
dual check valves to the rated working pressure of the connector, the 
rated working pressure of the dual check valve, expected surface 
pressure, or the collapse pressure of the coiled tubing, whichever is 
less.
    (f) Recordings. You must record test pressures during BOP and 
coiled tubing tests on a pressure chart, or with a digital recorder, 
unless otherwise approved by the District Manager. The test interval 
for each BOP system component must be 5 minutes, except for coiled 
tubing operations, which must include a 10 minute high-pressure test 
for the coiled tubing string. Your representative at the facility must 
certify that the charts are correct.
    (g) Operations log. The time, date, and results of all pressure 
tests, actuations, inspections, and crew drills of the BOP system, 
system components, and marine risers shall be recorded in the 
operations log. The BOP tests shall be documented in accordance with 
the following:
    (1) The documentation shall indicate the sequential order of BOP 
and auxiliary equipment testing and the pressure and duration of each 
test. As an alternate, the documentation in the operations log may 
reference a BOP test plan that contains the required information and is 
retained on file at the facility.

[[Page 64539]]

    (2) The control station used during the test shall be identified in 
the operations log. For a subsea system, the pod used during the test 
shall be identified in the operations log.
    (3) Any problems or irregularities observed during BOP and 
auxiliary equipment testing and any actions taken to remedy such 
problems or irregularities shall be noted in the operations log.
    (4) Documentation required to be entered in the operation log may 
instead be referenced in the operations log. All records including 
pressure charts, operations log, and referenced documents pertaining to 
BOP tests, actuations, and inspections, shall be available for BSEE 
review at the facility for the duration of well-workover activity. 
Following completion of the well-workover activity, all such records 
shall be retained for a period of 2 years at the facility, at the 
lessee's filed office nearest the OCS facility, or at another location 
conveniently available to the District Manager.
    (h) Subsea BOPs. Stump test a subsea BOP system before 
installation. You must:
    (1) Test all ROV intervention functions on your subsea BOP stack 
during the stump test. You must also test at least one set of rams 
during the initial test on the seafloor. You must submit test 
procedures with your APM for District Manager approval. You must:
    (i) Ensure that the ROV hot stabs are function tested and are 
capable of actuating, at a minimum, one set of pipe rams and one set of 
blind-shear rams and unlatching the LMRP;
    (ii) Document all your test results and make them available to BSEE 
upon request; and
    (2) Function test autoshear and deadman systems on your subsea BOP 
stack during the stump test. You must also test the deadman system 
during the initial test on the seafloor. You must:
    (i) Submit test procedures with your APM for District Manager 
approval.
    (ii) Document the results of each test and make them available to 
BSEE upon request.
    (3) Use water to stump test a subsea BOP system. You may use 
drilling or completion fluids to conduct subsequent tests of a subsea 
BOP system.


Sec.  250.617  What are my BOP inspection and maintenance requirements?

    (a) BOP inspections. (1) You must inspect your BOP system to ensure 
that the equipment functions properly. The BOP inspections must meet or 
exceed the provisions of Sections 17.10 and 18.10, Inspections, 
described in API RP 53, Recommended Practices for Blowout Prevention 
Equipment Systems for Drilling Wells (as incorporated by reference in 
Sec.  250.198). You must document the procedures used, record the 
results, and make them available to BSEE upon request. You must 
maintain your records on the rig for 2 years or from the date of your 
last major inspection, whichever is longer.
    (2) You must visually inspect your BOP system and marine riser at 
least once each day if weather and sea conditions permit. You may use 
television cameras to inspect this equipment. The District Manager may 
approve alternate methods and frequencies to inspect a marine riser.
    (b) BOP maintenance. You must maintain your BOP system to ensure 
that the equipment functions properly. The BOP maintenance must meet or 
exceed the provisions of Sections 17.11 and 18.11, Maintenance; and 
Sections 17.12 and 18.12, Quality Management, described in API RP 53, 
Recommended Practices for Blowout Prevention Equipment Systems for 
Drilling Wells (as incorporated by reference in Sec.  250.198). You 
must document the procedures used, record the results, and make them 
available to BSEE upon request. You must maintain your records on the 
rig for 2 years or from the date of your last major inspection, 
whichever is longer.


Sec.  250.618  Tubing and wellhead equipment.

    The lessee shall comply with the following requirements during 
well-workover operations with the tree removed:
    (a) No tubing string shall be placed in service or continue to be 
used unless such tubing string has the necessary strength and pressure 
integrity and is otherwise suitable for its intended use.
    (b) In the event of prolonged operations such as milling, fishing, 
jarring, or washing over that could damage the casing, the casing shall 
be pressure tested, calipered, or otherwise evaluated every 30 days and 
the results submitted to the District Manager.
    (c) When reinstalling the tree, you must:
    (1) Equip wells to monitor for casing pressure according to the 
following chart:

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

    (2) Follow the casing pressure management requirements in subpart E 
of this part.
    (d) Wellhead, tree, and related equipment shall have a pressure 
rating greater than the shut-in tubing pressure and shall be designed, 
installed, used, maintained, and tested so as to achieve and maintain 
pressure control. The tree shall be equipped with a minimum of one 
master valve and one surface safety valve in the vertical run of the 
tree when it is reinstalled.
    (e) Subsurface safety equipment shall be installed, maintained, and 
tested in compliance with Sec.  250.801 of this part.


Sec.  250.619  Wireline operations.

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

[[Page 64540]]

    (c) When the lubricator is initially installed on the well, it 
shall be successfully pressure tested to the expected shut-in surface 
pressure.

Subpart G [Reserved]

Subpart H--Oil and Gas Production Safety Systems


Sec.  250.800  General requirements.

    (a) Production safety equipment shall be designed, installed, used, 
maintained, and tested in a manner to assure the safety and protection 
of the human, marine, and coastal environments. Production safety 
systems operated in subfreezing climates shall utilize equipment and 
procedures selected with consideration of floating ice, icing, and 
other extreme environmental conditions that may occur in the area. 
Production shall not commence until the production safety system has 
been approved and a preproduction inspection has been requested by the 
lessee.
    (b) For all new floating production systems (FPSs) (e.g., column-
stabilized-units (CSUs); floating production, storage and offloading 
facilities (FPSOs); tension-leg platforms (TLPs); spars, etc.), you 
must do all of the following:
    (1) Comply with API RP 14J (as incorporated by reference in 30 CFR 
250.198);
    (2) Meet the drilling and production riser standards of API RP 2RD 
(as incorporated by reference in 30 CFR 250.198);
    (3) Design all stationkeeping systems for floating facilities to 
meet the standards of API RP 2SK (as incorporated by reference in 30 
CFR 250.198), as well as relevant U.S. Coast Guard regulations; and
    (4) Design stationkeeping systems for floating facilities to meet 
structural requirements in subpart I, Sec. Sec.  250.900 through 
250.921 of this part.


Sec.  250.801  Subsurface safety devices.

    (a) General. All tubing installations open to hydrocarbon-bearing 
zones shall be equipped with subsurface safety devices that will shut 
off the flow from the well in the event of an emergency unless, after 
application and justification, the well is determined by the District 
Manager to be incapable of natural flowing. These devices may consist 
of a surface-controlled subsurface safety valve (SSSV), a subsurface-
controlled SSSV, an injection valve, a tubing plug, or a tubing/annular 
subsurface safety device, and any associated safety valve lock or 
landing nipple.
    (b) Specifications for SSSVs. Surface-controlled and subsurface-
controlled SSSVs and safety valve locks and landing nipples installed 
in the OCS shall conform to the requirements in Sec.  250.806 of this 
part.
    (c) Surface-controlled SSSVs. All tubing installations open to a 
hydrocarbon-bearing zone which is capable of natural flow shall be 
equipped with a surface-controlled SSSV, except as specified in 
paragraphs (d), (f), and (g) of this section. The surface controls may 
be located on the site or a remote location. Wells not previously 
equipped with a surface-controlled SSSV and wells in which a surface-
controlled SSSV has been replaced with a subsurface-controlled SSSV in 
accordance with paragraph (d)(2) of this section shall be equipped with 
a surface-controlled SSSV when the tubing is first removed and 
reinstalled.
    (d) Subsurface-controlled SSSVs. Wells may be equipped with 
subsurface-controlled SSSVs in lieu of a surface-controlled SSSV 
provided the lessee demonstrates to the District Manager's satisfaction 
that one of the following criteria are met:
    (1) Wells not previously equipped with surface-controlled SSSVs 
shall be so equipped when the tubing is first removed and reinstalled,
    (2) The subsurface-controlled SSSV is installed in wells completed 
from a single-well or multiwell satellite caisson or seafloor 
completions, or
    (3) The subsurface-controlled SSSV is installed in wells with a 
surface-controlled SSSV that has become inoperable and cannot be 
repaired without removal and reinstallation of the tubing.
    (e) Design, installation, and operation of SSSVs. The SSSVs shall 
be designed, installed, operated, and maintained to ensure reliable 
operation.
    (1) The device shall be installed at a depth of 100 feet or more 
below the seafloor within 2 days after production is established. When 
warranted by conditions such as permafrost, unstable bottom conditions, 
hydrate formation, or paraffins, an alternate setting depth of the 
subsurface safety device may be approved by the District Manager.
    (2) Until a subsurface safety device is installed, the well shall 
be attended in the immediate vicinity so that emergency actions may be 
taken while the well is open to flow. During testing and inspection 
procedures, the well shall not be left unattended while open to 
production unless a properly operating subsurface-safety device has 
been installed in the well.
    (3) The well shall not be open to flow while the subsurface safety 
device is removed, except when flowing of the well is necessary for a 
particular operation such as cutting paraffin, bailing sand, or similar 
operations.
    (4) All SSSVs must be inspected, installed, maintained, and tested 
in accordance with American Petroleum Institute Recommended Practice 
14B, Recommended Practice for Design, Installation, Repair, and 
Operation of Subsurface Safety Valve Systems (as specified in Sec.  
250.198).
    (f) Subsurface safety devices in shut-in wells. (1) New completions 
(perforated but not placed on production) and completions shut in for a 
period of 6 months shall be equipped with either--
    (i) A pump-through-type tubing plug;
    (ii) A surface-controlled SSSV, provided the surface control has 
been rendered inoperative; or
    (iii) An injection valve capable of preventing backflow.
    (2) The setting depth of the subsurface safety device shall be 
approved by the District Manager on a case-by-case basis, when 
warranted by conditions such as permafrost, unstable bottom conditions, 
hydrate formations, and paraffins.
    (g) Subsurface safety devices in injection wells. A surface-
controlled SSSV or an injection valve capable of preventing backflow 
shall be installed in all injection wells. This requirement is not 
applicable if the District Manager concurs that the well is incapable 
of flowing. The lessee shall verify the no-flow condition of the well 
annually.
    (h) Temporary removal for routine operations. (1) Each wireline- or 
pumpdown-retrievable subsurface safety device may be removed, without 
further authorization or notice, for a routine operation which does not 
require the approval of a Form BSEE-0124, Application for Permit to 
Modify, in Sec.  250.601 of this part for a period not to exceed 15 
days.
    (2) The well shall be identified by a sign on the wellhead stating 
that the subsurface safety device has been removed. The removal of the 
subsurface safety device shall be noted in the records as required in 
Sec.  250.804(b) of this part. If the master valve is open, a trained 
person shall be in the immediate vicinity of the well to attend the 
well so that emergency actions may be taken, if necessary.
    (3) A platform well shall be monitored, but a person need not 
remain in the well-bay area continuously if the master valve is closed. 
If the well is on a satellite structure, it must be attended or a pump-
through plug installed in the tubing at least 100 feet below the mud 
line and the master valve closed, unless

[[Page 64541]]

otherwise approved by the District Manager.
    (4) The well shall not be allowed to flow while the subsurface 
safety device is removed, except when flowing the well is necessary for 
that particular operation. The provisions of this paragraph are not 
applicable to the testing and inspection procedures in Sec.  250.804 of 
this part.
    (i) Additional safety equipment. All tubing installations in which 
a wireline- or pumpdown-retrievable subsurface safety device is 
installed after the effective date of this subpart shall be equipped 
with a landing nipple with flow couplings or other protective equipment 
above and below to provide for the setting of the SSSV. The control 
system for all surface-controlled SSSVs shall be an integral part of 
the platform Emergency Shutdown System (ESD). In addition to the 
activation of the ESD by manual action on the platform, the system may 
be activated by a signal from a remote location. Surface-controlled 
SSSVs shall close in response to shut-in signals from the ESD and in 
response to the fire loop or other fire detection devices.
    (j) Emergency action. In the event of an emergency, such as an 
impending storm, any well not equipped with a subsurface safety device 
and which is capable of natural flow shall have the device properly 
installed as soon as possible with due consideration being given to 
personnel safety.


Sec.  250.802  Design, installation, and operation of surface 
production-safety systems.

    (a) General. All production facilities, including separators, 
treaters, compressors, headers, and flowlines shall be designed, 
installed, and maintained in a manner which provides for efficiency, 
safety of operation, and protection of the environment.
    (b) Platforms. You must protect all platform production facilities 
with a basic and ancillary surface safety system designed, analyzed, 
installed, tested, and maintained in operating condition in accordance 
with API RP 14C (as incorporated by reference in Sec.  250.198). If you 
use processing components other than those for which Safety Analysis 
Checklists are included in API RP 14C you must utilize the analysis 
technique and documentation specified therein to determine the effects 
and requirements of these components on the safety system. Safety 
device requirements for pipelines are under Sec.  250.1004.
    (c) Specification for surface safety valves (SSV) and underwater 
safety valves (USV). All wellhead SSVs, USVs, and their actuators which 
are installed in the OCS shall conform to the requirements in Sec.  
250.806 of this part.
    (d) Use of SSVs and USV's. All SSVs and USVs must be inspected, 
installed, maintained, and tested in accordance with API RP 14H, 
Recommended Practice for Installation, Maintenance, and Repair of 
Surface Safety Valves and Underwater Safety Valves Offshore (as 
incorporated by reference in Sec.  250.198). If any SSV or USV does not 
operate properly or if any fluid flow is observed during the leakage 
test, the valve shall be repaired or replaced.
    (e) Approval of safety-systems design and installation features. 
Prior to installation, the lessee shall submit, in duplicate for 
approval to the District Manager a production safety system application 
containing information relative to design and installation features. 
Information concerning approved design and installation features shall 
be maintained by the lessee at the lessee's offshore field office 
nearest the OCS facility or other location conveniently available to 
the District Manager. All approvals are subject to field verifications. 
The application shall include the following:
    (1) A schematic flow diagram showing tubing pressure, size, 
capacity, design working pressure of separators, flare scrubbers, 
treaters, storage tanks, compressors, pipeline pumps, metering devices, 
and other hydrocarbon-handling vessels.
    (2) A schematic piping flow diagram (API RP 14C, Figure E, as 
incorporated by reference in Sec.  250.198) and the related Safety 
analysis Function Evaluation chart (API RP 14C, subsection 4.3c, as 
incorporated by reference in Sec.  250.198).
    (3) A schematic piping diagram showing the size and maximum 
allowable working pressures as determined in accordance with API RP 
14E, Design and Installation of Offshore Production Platform Piping 
Systems (as incorporated by reference in Sec.  250.198).
    (4) Electrical system information including the following:
    (i) A plan for each platform deck outlining all hazardous areas 
classified according to API RP 500, Recommended Practice for 
Classification of Locations for Electrical Installations at Petroleum 
Facilities Classified as Class I, Division 1 and Division 2, or API RP 
505, Recommended Practice for Classification of Locations for 
Electrical Installations at Petroleum Facilities Classified as Class I, 
Zone 0, Zone 1, and Zone 2 (as incorporated by reference in Sec.  
250.198), and outlining areas in which potential ignition sources, 
other than electrical, are to be installed. The area outlined will 
include the following information:
    (A) All major production equipment, wells, and other significant 
hydrocarbon sources and a description of the type of decking, ceiling, 
walls (e.g., grating or solid) and firewalls; and
    (B) Location of generators, control rooms, panel boards, major 
cabling/conduit routes, and identification of the primary wiring method 
(e.g., type cable, conduit, or wire).
    (ii) Elementary electrical schematic of any platform safety shut-
down system with a functional legend.
    (5) Certification that the design for the mechanical and electrical 
systems to be installed were approved by registered professional 
engineers. After these systems are installed, the lessee shall submit a 
statement to the District Manager certifying that new installations 
conform to the approved designs of this subpart.
    (6) The design and schematics of the installation and maintenance 
of all fire- and gas-detection systems shall include the following:
    (i) Type, location, and number of detection sensors;
    (ii) Type and kind of alarms, including emergency equipment to be 
activated;
    (iii) Method used for detection;
    (iv) Method and frequency of calibration; and
    (v) A functional block diagram of the detection system, including 
the electric power supply.
    (7) The service fee listed in Sec.  250.125. The fee you must pay 
will be determined by the number of components involved in the review 
and approval process.


Sec.  250.803  Additional production system requirements.

    (a) For all production platforms, you must comply with the 
following production safety system requirements, in addition to the 
requirements of Sec.  250.802 of this subpart and the requirements of 
API RP 14C (as incorporated by reference in Sec.  250.198).
    (b) Design, installation, and operation of additional production 
systems--(1) Pressure and fired vessels. Pressure and fired vessels 
must be designed, fabricated, and code stamped in accordance with the 
applicable provisions of Sections I, IV, and VIII of the American 
Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code. 
Pressure and fired vessels must have maintenance inspection, rating, 
repair, and alteration performed in accordance with the applicable 
provisions of API Pressure Vessel Inspections Code: In-Service 
Inspection,

[[Page 64542]]

Rating, Repair, and Alteration, API 510 (except Sections 5.8 and 9.5) 
(as incorporated by reference in Sec.  250.198).
    (i) Pressure relief valves shall be designed, installed, and 
maintained in accordance with applicable provisions of sections I, IV, 
and VIII of the ASME Boiler and Pressure Vessel Code. The relief valves 
shall conform to the valve-sizing and pressure-relieving requirements 
specified in these documents; however, the relief valves, except 
completely redundant relief valves, shall be set no higher than the 
maximum-allowable working pressure of the vessel. All relief valves and 
vents shall be piped in such a way as to prevent fluid from striking 
personnel or ignition sources.
    (ii) Steam generators operating at less than 15 pounds per square 
inch gauge (psig) shall be equipped with a level safety low (LSL) 
sensor which will shut off the fuel supply when the water level drops 
below the minimum safe level. Steam generators operating at greater 
than 15 psig require, in addition to an LSL, a water-feeding device 
which will automatically control the water level.
    (iii) The lessee shall use pressure recorders to establish the new 
operating pressure ranges of pressure vessels at any time when there is 
a change in operating pressures that requires new settings for the 
high-pressure shut-in sensor and/or the low-pressure shut-in sensor as 
provided herein. The pressure-recorder charts used to determine current 
operating pressure ranges shall be maintained at the lessee's field 
office nearest the OCS facility or at other locations conveniently 
available to the District Manager. The high-pressure shut-in sensor 
shall be set no higher than 15 percent or 5 psi, whichever is greater, 
above the highest operating pressure of the vessel. This setting shall 
also be set sufficiently below (5 percent or 5 psi, whichever is 
greater) the relief valve's set pressure to assure that the pressure 
source is shut in before the relief valve activates. The low-pressure 
shut-in sensor shall activate no lower than 15 percent or 5 psi, 
whichever is greater, below the lowest pressure in the operating range. 
The activation of low-pressure sensors on pressure vessels which 
operate at less than 5 psi shall be approved by the District Manager on 
a case-by-case basis.
    (2) Flowlines. (i) You must equip flowlines from wells with high- 
and low-pressure shut-in sensors located in accordance with section A.1 
and Figure A1 of API RP 14C (as incorporated by reference in Sec.  
250.198). The lessee shall use pressure recorders to establish the new 
operating pressure ranges of flowlines at any time when there is a 
significant change in operating pressures. The most recent pressure-
recorder charts used to determine operating pressure ranges shall be 
maintained at the lessee's field office nearest the OCS facility or at 
other locations conveniently available to the District Manager. The 
high-pressure shut-in sensor(s) shall be set no higher than 15 percent 
or 5 psi, whichever is greater, above the highest operating pressure of 
the line. But in all cases, it shall be set sufficiently below the 
maximum shut-in wellhead pressure or the gas-lift supply pressure to 
assure actuation of the SSV. The low-pressure shut-in sensor(s) shall 
be set no lower than 15 percent or 5 psi, whichever is greater, below 
the lowest operating pressure of the line in which it is installed.
    (ii) If a well flows directly to the pipeline before separation, 
the flowline and valves from the well located upstream of and including 
the header inlet valve(s) shall have a working pressure equal to or 
greater than the maximum shut-in pressure of the well unless the 
flowline is protected by one of the following:
    (A) A relief valve which vents into the platform flare scrubber or 
some other location approved by the District Manager. The platform 
flare scrubber shall be designed to handle, without liquid-hydrocarbon 
carryover to the flare, the maximum-anticipated flow of liquid 
hydrocarbons which may be relieved to the vessel.
    (B) Two SSV's with independent high-pressure sensors installed with 
adequate volume upstream of any block valve to allow sufficient time 
for the valve(s) to close before exceeding the maximum allowable 
working pressure.
    (iii) If you are installing flowlines constructed of unbonded 
flexible pipe on a floating platform, you must:
    (A) Review the manufacturer's Design Methodology Verification 
Report and the independent verification agent's (IVA's) certificate for 
the design methodology contained in that report to ensure that the 
manufacturer has complied with the requirements of API Spec 17J (as 
incorporated by reference in Sec.  250.198);
    (B) Determine that the unbonded flexible pipe is suitable for its 
intended purpose on the lease or pipeline right-of-way;
    (C) Submit to the BSEE District Manager the manufacturer's design 
specifications for the unbonded flexible pipe; and
    (D) Submit to the BSEE District Manager a statement certifying that 
the pipe is suitable for its intended use and that the manufacturer has 
complied with the IVA requirements of API Spec 17J (as incorporated by 
reference in Sec.  250.198).
    (3) Safety sensors. All shutdown devices, valves, and pressure 
sensors shall function in a manual reset mode. Sensors with integral 
automatic reset shall be equipped with an appropriate device to 
override the automatic reset mode. All pressure sensors shall be 
equipped to permit testing with an external pressure source.
    (4) ESD. The ESD must conform to the requirements of Appendix C, 
section C1, of API RP 14C (as incorporated by reference in Sec.  
250.198), and the following:
    (i) The manually operated ESD valve(s) shall be quick-opening and 
nonrestricted to enable the rapid actuation of the shutdown system. 
Only ESD stations at the boat landing may utilize a loop of breakable 
synthetic tubing in lieu of a valve.
    (ii) Closure of the SSV shall not exceed 45 seconds after automatic 
detection of an abnormal condition or actuation of an ESD. The surface-
controlled SSSV shall close in not more than 2 minutes after the shut-
in signal has closed the SSV. Design-delayed closure time greater than 
2 minutes shall be justified by the lessee based on the individual 
well's mechanical/production characteristics and be approved by the 
District Manager.
    (iii) A schematic of the ESD which indicates the control functions 
of all safety devices for the platforms shall be maintained by the 
lessee on the platform or at the lessee's field office nearest the OCS 
facility or other location conveniently available to the District 
Manager.
    (5) Engines: (i) Engine exhaust. You must equip engine exhausts to 
comply with the insulation and personnel protection requirements of API 
RP 14C, section 4.2c(4) (as incorporated by reference in Sec.  
250.198). Exhaust piping from diesel engines must be equipped with 
spark arresters.
    (ii) Diesel engine air intake. All diesel engine air intakes must 
be equipped with a device to shutdown the diesel engine in the event of 
runaway. Diesel engines that are continuously attended must be equipped 
with either remote operated manual or automatic shutdown devices. 
Diesel engines that are not continuously attended must be equipped with 
automatic shutdown devices.
    (6) Glycol dehydration units. A pressure relief system or an 
adequate vent shall be installed on the glycol regenerator (reboiler) 
which will prevent overpressurization. The

[[Page 64543]]

discharge of the relief valve shall be vented in a nonhazardous manner.
    (7) Gas compressors. You must equip compressor installations with 
the following protective equipment as required in API RP 14C, Sections 
A4 and A8 (as incorporated by reference in Sec.  250.198).
    (i) A Pressure Safety High (PSH), a Pressure Safety Low (PSL), a 
Pressure Safety Valve (PSV), and a Level Safety High (LSH), and an LSL 
to protect each interstage and suction scrubber.
    (ii) A Temperature Safety High (TSH) on each compressor discharge 
cylinder.
    (iii) The PSH and PSL shut-in sensors and LSH shut-in controls 
protecting compressor suction and interstage scrubbers shall be 
designated to actuate automatic shutdown valves (SDV) located in each 
compressor suction and fuel gas line so that the compressor unit and 
the associated vessels can be isolated from all input sources. All 
automatic SDV's installed in compressor suction and fuel gas piping 
shall also be actuated by the shutdown of the prime mover. Unless 
otherwise approved by the District Manager, gas--well gas affected by 
the closure of the automatic SDV on a compressor suction shall be 
diverted to the pipeline or shut in at the wellhead.
    (iv) A blowdown valve is required on the discharge line of all 
compressor installations of 1,000 horsepower (746 kilowatts) or 
greater.
    (8) Firefighting systems. Firefighting systems for both open and 
totally enclosed platforms installed for extreme weather conditions or 
other reasons shall conform to subsection 5.2, Firewater systems, of 
API RP 14G (as incorporated by reference in Sec.  250.198), Fire 
Prevention and Control Open Type Offshore Production Platforms, and 
shall require approval of the District Manager. The following 
additional requirements shall apply for both open- and closed-
production platforms:
    (i) A firewater system consisting of rigid pipe with firehose 
stations or fixed firewater monitors shall be installed. The firewater 
system shall be installed to provide needed protection in all areas 
where production-handling equipment is located. A fixed waterspray 
system shall be installed in enclosed well-bay areas where hydrocarbon 
vapors may accumulate.
    (ii) Fuel or power for firewater pump drivers shall be available 
for at least 30 minutes of run time during a platform shut-in. If 
necessary, an alternate fuel or power supply shall be installed to 
provide for this pump-operating time unless an alternate firefighting 
system has been approved by the District Manager.
    (iii) A firefighting system using chemicals may be used in lieu of 
a water system if the District Manager determines that the use of a 
chemical system provides equivalent fire-protection control.
    (iv) A diagram of the firefighting system showing the location of 
all firefighting equipment shall be posted in a prominent place on the 
facility or structure.
    (v) For operations in subfreezing climates, the lessee shall 
furnish evidence to the District Manager that the firefighting system 
is suitable for the conditions.
    (9) Fire- and gas-detection system. (i) Fire (flame, heat, or 
smoke) sensors shall be installed in all enclosed classified areas. Gas 
sensors shall be installed in all inadequately ventilated, enclosed 
classified areas. Adequate ventilation is defined as ventilation which 
is sufficient to prevent accumulation of significant quantities of 
vapor-air mixture in concentrations over 25 percent of the lower 
explosive limit (LEL). One approved method of providing adequate 
ventilation is a change of air volume each 5 minutes or 1 cubic foot of 
air-volume flow per minute per square foot of solid floor area, 
whichever is greater. Enclosed areas (e.g., buildings, living quarters, 
or doghouses) are defined as those areas confined on more than four of 
their six possible sides by walls, floors, or ceilings more restrictive 
to air flow than grating or fixed open louvers and of sufficient size 
to all entry of personnel. A classified area is any area classified 
Class I, Group D, Division 1 or 2, following the guidelines of API RP 
500 (as incorporated by reference in Sec.  250.198), or any area 
classified Class I, Zone 0, Zone 1, or Zone 2, following the guidelines 
of API RP 505 (as incorporated by reference in Sec.  250.198).
    (ii) All detection systems shall be capable of continuous 
monitoring. Fire-detection systems and portions of combustible gas-
detection systems related to the higher gas concentration levels shall 
be of the manual-reset type. Combustible gas-detection systems related 
to the lower gas-concentration level may be of the automatic-reset 
type.
    (iii) A fuel-gas odorant or an automatic gas-detection and alarm 
system is required in enclosed, continuously manned areas of the 
facility which are provided with fuel gas. Living quarters and 
doghouses not containing a gas source and not located in a classified 
area do not require a gas detection system.
    (iv) The District Manager may require the installation and 
maintenance of a gas detector or alarm in any potentially hazardous 
area.
    (v) Fire- and gas-detection systems must be an approved type, 
designed and installed according to API RP 14C, API RP 14G, and either 
API RP 14F or API RP 14FZ (the preceding four documents as incorporated 
by reference in Sec.  250.198).
    (10) Electrical equipment. Electrical equipment and systems shall 
be designed, installed, and maintained in accordance with the 
requirements in Sec.  250.114 of this part.
    (11) Erosion. A program of erosion control shall be in effect for 
wells or fields having a history of sand production. The erosion-
control program may include sand probes, X-ray, ultrasonic, or other 
satisfactory monitoring methods. Records by lease, indicating the wells 
which have erosion-control programs in effect and the results of the 
programs, shall be maintained by the lessee for a period of 2 years and 
shall be made available to BSEE upon request.
    (c) General platform operations. (1) Surface or subsurface safety 
devices shall not be bypassed or blocked out of service unless they are 
temporarily out of service for startup, maintenance, or testing 
procedures. Only the minimum number of safety devices shall be taken 
out of service. Personnel shall monitor the bypassed or blocked-out 
functions until the safety devices are placed back in service. Any 
surface or subsurface safety device which is temporarily out of service 
shall be flagged.
    (2) When wells are disconnected from producing facilities and blind 
flanged, equipped with a tubing plug, or the master valves have been 
locked closed, you are not required to comply with the provisions of 
API RP 14C (as incorporated by reference in Sec.  250.198) or this 
regulation concerning the following:
    (i) Automatic fail-close SSV's on wellhead assemblies, and
    (ii) The PSH and PSL shut-in sensors in flowlines from wells.
    (3) When pressure or atmospheric vessels are isolated from 
production facilities (e.g., inlet valve locked closed or inlet blind-
flanged) and are to remain isolated for an extended period of time, 
safety device compliance with API RP 14C or this subpart is not 
required.
    (4) All open-ended lines connected to producing facilities and 
wells shall be plugged or blind-flanged, except those lines designed to 
be open-ended such as flare or vent lines.
    (d) Welding and burning practices and procedures. All welding, 
burning, and hot-tapping activities shall be conducted according to the 
specific

[[Page 64544]]

requirements in Sec. Sec.  250.109 through 250.113 of this part.


Sec.  250.804  Production safety-system testing and records.

    (a) Inspection and testing. The safety-system devices shall be 
successfully inspected and tested by the lessee at the interval 
specified below or more frequently if operating conditions warrant. 
Testing must be in accordance with API RP 14C, Appendix D (as 
incorporated by reference in Sec.  250.198), and the following:
    (1) Testing requirements for subsurface safety devices are as 
follows:
    (i) Each surface-controlled subsurface safety device installed in a 
well, including such devices in shut-in and injection wells, shall be 
tested in place for proper operation when installed or reinstalled and 
thereafter at intervals not exceeding 6 months. If the device does not 
operate properly, or if a liquid leakage rate in excess of 200 cubic 
centimeters per minute or a gas leakage rate in excess of 5 cubic feet 
per minute is observed, the device shall be removed, repaired and 
reinstalled, or replaced. Testing shall be in accordance with API RP 
14B (as incorporated by reference in Sec.  250.198) to ensure proper 
operation.
    (ii) Each subsurface-controlled SSSV installed in a well shall be 
removed, inspected, and repaired or adjusted, as necessary, and 
reinstalled or replaced at intervals not exceeding 6 months for those 
valves not installed in a landing nipple and 12 months for those valves 
installed in a landing nipple.
    (iii) Each tubing plug installed in a well shall be inspected for 
leakage by opening the well to possible flow at intervals not exceeding 
6 months. If a liquid leakage rate in excess of 200 cubic centimeters 
per minute or a gas leakage rate in excess of 5 cubic feet per minute 
is observed, the device shall be removed, repaired and reinstalled, or 
replaced. An additional tubing plug may be installed in lieu of 
removal.
    (iv) Injection valves shall be tested in the manner as outlined for 
testing tubing plugs in paragraph (a)(1)(iii) of this section. Leakage 
rates outlined in paragraph (a)(1)(iii) of this section shall apply.
    (2) All PSV's shall be tested for operation at least once every 12 
months. These valves shall be either bench-tested or equipped to permit 
testing with an external pressure source. Weighted disk vent valves 
used as PSV's on atmospheric tanks may be disassembled and inspected in 
lieu of function testing.
    (3) The following safety devices (excluding electronic pressure 
transmitters and level sensors) must be tested at least once each 
calendar month, but at no time will more than 6 weeks elapse between 
tests:
    (i) All PSH and PSL,
    (ii) All LSH and LSL controls,
    (iii) All automatic inlet SDV's which are actuated by a sensor on a 
vessel or compressor, and
    (iv) All SDV's in liquid discharge lines and actuated by vessel 
low-level sensors.
    (4) The following electronic pressure transmitters and level 
sensors must be tested at least once every 3 months, but at no time may 
more than 120 days elapse between tests:
    (i) All PSH and PSL, and
    (ii) All LSH and LSL controls.
    (5) All SSV's and USV's shall be tested for operation and for 
leakage at least once each calendar month, but at no time shall more 
than 6 weeks elapse between tests. The SSV's and USV's must be tested 
in accordance with the test procedures specified in API RP 14H (as 
incorporated by reference in Sec.  250.198). If the SSV or USV does not 
operate properly or if any fluid flow is observed during the leakage 
test, the valve shall be repaired or replaced.
    (6) All flowline Flow Safety Valves (FSV) shall be checked for 
leakage at least once each calendar month, but at no time shall more 
than 6 weeks elapse between tests. The FSV's must be tested for leakage 
in accordance with the test procedures specified in API RP 14C, 
Appendix D, section D4, table D2, subsection D (as incorporated by 
reference in Sec.  250.198). If the leakage measured exceeds a liquid 
flow of 200 cubic centimeters per minute or a gas flow of 5 cubic feet 
per minute, the FSV's shall be repaired or replaced.
    (7) The TSH shutdown controls installed on compressor installations 
which can be nondestructively tested shall be tested every 6 months and 
repaired or replaced as necessary.
    (8) All pumps for firewater systems shall be inspected and operated 
weekly.
    (9) All fire- (flame, heat, or smoke) detection systems shall be 
tested for operation and recalibrated every 3 months provided that 
testing can be performed in a nondestructive manner. Open flame or 
devices operating at temperatures which could ignite a methane-air 
mixture shall not be used. All combustible gas-detection systems shall 
be calibrated every 3 months.
    (10) All TSH devices shall be tested at least once every 12 months, 
excluding those addressed in paragraph (a)(7) of this section and those 
which would be destroyed by testing. Burner safety low and flow safety 
low devices shall also be tested at least once every 12 months.
    (11) The ESD shall be tested for operation at least once each 
calendar month, but at no time shall more than 6 weeks elapse between 
tests. The test shall be conducted by alternating ESD stations monthly 
to close at least one wellhead SSV and verify a surface-controlled SSSV 
closure for that well as indicated by control circuitry actuation.
    (12) Prior to the commencement of production, the lessee shall 
notify the District Manager when the lessee is ready to conduct a 
preproduction test and inspection of the integrated safety system. The 
lessee shall also notify the District Manager upon commencement of 
production in order that a complete inspection may be conducted.
    (b) Records. The lessee shall maintain records for a period of 2 
years for each subsurface and surface safety device installed. These 
records shall be maintained by the lessee at the lessee's field office 
nearest the OCS facility or other locations conveniently available to 
the District Manager. These records shall be available for review by a 
representative of BSEE. The records shall show the present status and 
history of each device, including dates and details of installation, 
removal, inspection, testing, repairing, adjustments, and 
reinstallation.


Sec.  250.805  Safety device training.

    Personnel installing, inspecting, testing, and maintaining these 
safety devices and personnel operating the production platforms shall 
be qualified in accordance with 30 CFR 250, subpart O.


Sec.  250.806  Safety and pollution prevention equipment quality 
assurance requirements.

    (a) General requirements. (1) Except as provided in paragraph 
(b)(1) of this section, you may install only certified safety and 
pollution prevention equipment (SPPE) in wells located on the OCS. SPPE 
includes the following:
    (i) Surface safety valves (SSV) and actuators;
    (ii) Underwater safety valves (USV) and actuators; and
    (iii) Subsurface safety valves (SSSV) and associated safety valve 
locks and landing nipples.
    (2) Certified SPPE is equipment the manufacturer certifies as 
manufactured under a quality assurance program BSEE recognizes. BSEE 
considers all other SPPE as noncertified. BSEE recognizes two quality 
assurance programs:
    (i) 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 (as incorporated by 
reference in Sec.  250.198); and

[[Page 64545]]

    (ii) API Spec Q1, Specification for Quality Programs for the 
Petroleum, Petrochemical and Natural Gas Industry (as incorporated by 
reference in Sec.  250.198).
    (3) All SSV's and USV's must meet the technical specifications of 
API Spec 6A and 6AV1. All SSSVs must meet the technical specifications 
of API Specification 14A (as incorporated by reference in Sec.  
250.198). However, SSSVs and related equipment planned to be used in 
high pressure high temperature environments must meet the additional 
requirements set forth in Sec.  250.807.
    (4) For information on all standards mentioned in this section, see 
Sec.  250.198.
    (b) Use of noncertified SPPE. (1) Before April 1, 1998, you may 
continue to use and install noncertified SPPE if it was in your 
inventory as of April 1, 1988, and was included in a list of 
noncertified SPPE submitted to BSEE prior to August 29, 1988.
    (2) On or after April 1, 1998:
    (i) You may not install additional noncertified SPPE; and
    (ii) When noncertified SPPE that is already in service requires 
offsite repair, remanufacturing, or hot work such as welding, you must 
replace it with certified SPPE.
    (c) Recognizing other quality assurance programs. The BSEE will 
consider recognizing other quality assurance programs covering the 
manufacture of SPPE. If you want BSEE to evaluate other quality 
assurance programs, submit relevant information about the program and 
reasons for recognition by BSEE to the Chief, Office of Offshore 
Regulatory Programs; Bureau of Safety and Environmental Enforcement; 
MS-4020; 381 Elden Street, Herndon, Virginia 20170-4817.


Sec.  250.807  Additional requirements for subsurface safety valves and 
related equipment installed in high pressure high temperature (HPHT) 
environments.

    (a) If you plan to install SSSVs and related equipment in an HPHT 
environment, you must submit detailed information with your Application 
for Permit to Drill (APD), Application for Permit to Modify (APM), or 
Deepwater Operations Plan (DWOP) that demonstrates the SSSVs and 
related equipment are capable of performing in the applicable HPHT 
environment. Your detailed information must include the following:
    (1) A discussion of the SSSVs' and related equipment's design 
verification analysis;
    (2) A discussion of the SSSVs' and related equipment's design 
validation and functional testing process and procedures used; and
    (3) An explanation of why the analysis, process, and procedures 
ensure that the SSSVs and related equipment are fit-for-service in the 
applicable HPHT environment.
    (b) For this section, HPHT environment means when one or more of 
the following well conditions exist:
    (1) The completion of the well requires completion equipment or 
well control equipment assigned a pressure rating greater than 15,000 
psig or a temperature rating greater than 350 degrees Fahrenheit;
    (2) The maximum anticipated surface pressure or shut-in tubing 
pressure is greater than 15,000 psig on the seafloor for a well with a 
subsea wellhead or at the surface for a well with a surface wellhead; 
or
    (3) The flowing temperature is equal to or greater than 350 degrees 
Fahrenheit on the seafloor for a well with a subsea wellhead or at the 
surface for a well with a surface wellhead.
    (c) For this section, related equipment includes wellheads, tubing 
heads, tubulars, packers, threaded connections, seals, seal assemblies, 
production trees, chokes, well control equipment, and any other 
equipment that will be exposed to the HPHT environment.


Sec.  250.808  Hydrogen sulfide.

    Production operations in zones known to contain hydrogen sulfide 
(H2S) or in zones where the presence of H2S is 
unknown, as defined in Sec.  250.490 of this part, shall be conducted 
in accordance with that section and other relevant requirements of 
subpart H, Production Safety Systems.

Subpart I--Platforms and Structures

General Requirements for Platforms


Sec.  250.900  What general requirements apply to all platforms?

    (a) You must design, fabricate, install, use, maintain, inspect, 
and assess all platforms and related structures on the Outer 
Continental Shelf (OCS) so as to ensure their structural integrity for 
the safe conduct of drilling, workover, and production operations. In 
doing this, you must consider the specific environmental conditions at 
the platform location.
    (b) You must also submit an application under Sec.  250.905 of this 
subpart and obtain the approval of the Regional Supervisor before 
performing any of the activities described in the following table:

------------------------------------------------------------------------
   Activity requiring application and     Conditions for conducting the
                approval                             activity
------------------------------------------------------------------------
(1) Install a platform. This includes    (i) You must adhere to the
 placing a newly constructed platform     requirements of this subpart,
 at a location or moving an existing      including the industry
 platform to a new site.                  standards in Sec.   250.901.
                                         (ii) If you are installing a
                                          floating platform, you must
                                          also adhere to U.S. Coast
                                          Guard (USCG) regulations for
                                          the fabrication, installation,
                                          and inspection of floating OCS
                                          facilities.
(2) Major modification to any platform.  (i) You must adhere to the
 This includes any structural changes     requirements of this subpart,
 that materially alter the approved       including the industry
 plan or cause a major deviation from     standards in Sec.   250.901.
 approved operations and any             (ii) Before you make a major
 modification that increases loading on   modification to a floating
 a platform by 10 percent or more.        platform, you must obtain
                                          approval from both the BSEE
                                          and the USCG for the
                                          modification.
(3) Major repair of damage to any        (i) You must adhere to the
 platform. This includes any corrective   requirements of this subpart,
 operations involving structural          including the industry
 members affecting the structural         standards in Sec.   250.901.
 integrity of a portion or all of the    (ii) Before you make a major
 platform.                                repair to a floating platform,
                                          you must obtain approval from
                                          both the BSEE and the USCG for
                                          the repair.
(4) Convert an existing platform at the  (i) The Regional Supervisor
 current location for a new purpose.      will determine on a case-by-
                                          case basis the requirements
                                          for an application for
                                          conversion of an existing
                                          platform at the current
                                          location.
                                         (ii) At a minimum, your
                                          application must include: the
                                          converted platform's intended
                                          use; and a demonstration of
                                          the adequacy of the design and
                                          structural condition of the
                                          converted platform.
                                         (iii) If a floating platform,
                                          you must also adhere to USCG
                                          regulations for the
                                          fabrication, installation, and
                                          inspection of floating OCS
                                          facilities.

[[Page 64546]]

 
(5) Convert an existing mobile offshore  (i) The Regional Supervisor
 drilling unit (MODU) for a new purpose.  will determine on a case-by-
                                          case basis the requirements
                                          for an application for
                                          conversion of an existing
                                          MODU.
                                         (ii) At a minimum, your
                                          application must include: the
                                          converted MODU's intended
                                          location and use; a
                                          demonstration of the adequacy
                                          of the design and structural
                                          condition of the converted
                                          MODU; and a demonstration that
                                          the level of safety for the
                                          converted MODU is at least
                                          equal to that of re-used
                                          platforms.
                                         (iii) You must also adhere to
                                          USCG regulations for the
                                          fabrication, installation, and
                                          inspection of floating OCS
                                          facilities.
------------------------------------------------------------------------

     (c) Under emergency conditions, you may make repairs to primary 
structural elements to restore an existing permitted condition without 
submitting an application or receiving prior BSEE approval for up to 
120-calendar days following an event. You must notify the Regional 
Supervisor of the damage that occurred within 24 hours of its 
discovery, and you must provide a written completion report to the 
Regional Supervisor of the repairs that were made within 1 week after 
completing the repairs. If you make emergency repairs on a floating 
platform, you must also notify the USCG.
    (d) You must determine if your new platform or major modification 
to an existing platform is subject to the Platform Verification Program 
(PVP). Section 250.910 of this subpart fully describes the facilities 
that are subject to the PVP. If you determine that your platform is 
subject to the PVP, you must follow the requirements of Sec. Sec.  
250.909 through 250.918 of this subpart.
    (e) You must submit notification of the platform installation date 
and the final as-built location data to the Regional Supervisor within 
45-calendar days of completion of platform installation.
    (1) For platforms not subject to the Platform Verification Program 
(PVP), BSEE will cancel the approved platform application 1 year after 
the approval has been granted if the platform has not been installed. 
If BSEE cancels the approval, you must resubmit your platform 
application and receive BSEE approval if you still plan to install the 
platform.
    (2) For platforms subject to the PVP, cancellation of an approval 
will be on an individual platform basis. For these platforms, BSEE will 
identify the date when the installation approval will be cancelled (if 
installation has not occurred) during the application and approval 
process. If BSEE cancels your installation approval, you must resubmit 
your platform application and receive BSEE approval if you still plan 
to install the platform.


Sec.  250.901  What industry standards must your platform meet?

    (a) In addition to the other requirements of this subpart, your 
plans for platform design, analysis, fabrication, installation, use, 
maintenance, inspection and assessment must, as appropriate, conform 
to:
    (1) ACI Standard 318-95, Building Code Requirements for Reinforced 
Concrete (ACI 318-95) and Commentary (ACI 318R-95) (incorporated by 
reference at Sec.  250.198);
    (2) ACI 357R-84, Guide for the Design and Construction of Fixed 
Offshore Concrete Structures, 1984; reapproved 1997 (incorporated by 
reference at Sec.  250.198);
    (3) ANSI/AISC 360-05, Specification for Structural Steel Buildings, 
(as specified in Sec.  250.198);
    (4) American Petroleum Institute (API) Bulletin 2INT-DG, Interim 
Guidance for Design of Offshore Structures for Hurricane Conditions, 
(as incorporated by reference in Sec.  250.198);
    (5) API Bulletin 2INT-EX, Interim Guidance for Assessment of 
Existing Offshore Structures for Hurricane Conditions, (as incorporated 
by reference in Sec.  250.198);
    (6) API Bulletin 2INT-MET, Interim Guidance on Hurricane Conditions 
in the Gulf of Mexico, (as incorporated by reference in Sec.  250.198);
    (7) API Recommend Practice (RP) 2A-WSD, RP for Planning, Designing, 
and Constructing Fixed Offshore Platforms--Working Stress Design (as 
incorporated by reference in Sec.  250.198);
    (8) API RP 2FPS, Recommended Practice for Planning, Designing, and 
Constructing Floating Production Systems, (as incorporated by reference 
in Sec.  250.198);
    (9) API RP 2I, In-Service Inspection of Mooring Hardware for 
Floating Drilling Units (as incorporated by reference in Sec.  
250.198);
    (10) API RP 2RD, Design of Risers for Floating Production Systems 
(FPSs) and Tension-Leg Platforms (TLPs), (as incorporated by reference 
in Sec.  250.198);
    (11) API RP 2SK, Recommended Practice for Design and Analysis of 
Station Keeping Systems for Floating Structures, (as incorporated by 
reference in Sec.  250.198);
    (12) API RP 2SM, Recommended Practice for Design, Manufacture, 
Installation, and Maintenance of Synthetic Fiber Ropes for Offshore 
Mooring, (as incorporated by reference in Sec.  250.198);
    (13) API RP 2T, Recommended Practice for Planning, Designing and 
Constructing Tension Leg Platforms, (as incorporated by reference in 
Sec.  250.198);
    (14) API RP 14J, Recommended Practice for Design and Hazards 
Analysis for Offshore Production Facilities, (as incorporated by 
reference in Sec.  250.198);
    (15) American Society for Testing and Materials (ASTM) Standard C 
33-07, approved December 15, 2007, Standard Specification for Concrete 
Aggregates (as incorporated by reference in Sec.  250.198);
    (16) ASTM Standard C 94/C 94M-07, approved January 1, 2007, 
Standard Specification for Ready-Mixed Concrete (as incorporated by 
reference in Sec.  250.198);
    (17) ASTM Standard C 150-07, approved May 1, 2007, Standard 
Specification for Portland Cement (as incorporated by reference in 
Sec.  250.198);
    (18) ASTM Standard C 330-05, approved December 15, 2005, Standard 
Specification for Lightweight Aggregates for Structural Concrete (as 
incorporated by reference in Sec.  250.198);
    (19) ASTM Standard C 595-08, approved January 1, 2008, Standard 
Specification for Blended Hydraulic Cements (as incorporated by 
reference in Sec.  250.198);
    (20) AWS D1.1, Structural Welding Code--Steel, including 
Commentary, (as incorporated by reference in Sec.  250.198);
    (21) AWS D1.4, Structural Welding Code--Reinforcing Steel, (as 
incorporated by reference in Sec.  250.198);
    (22) AWS D3.6M, Specification for Underwater Welding, (as 
incorporated by reference in Sec.  250.198);
    (23) NACE Standard MR0175, Sulfide Stress Cracking Resistant 
Metallic Materials for Oilfield Equipment, (as incorporated by 
reference in Sec.  250.198);
    (24) NACE Standard RP0176-2003, Item No. 21018, Standard

[[Page 64547]]

Recommended Practice, Corrosion Control of Steel Fixed Offshore 
Structures Associated with Petroleum Production.
    (b) You must follow the requirements contained in the documents 
listed under paragraph (a) of this section insofar as they do not 
conflict with other provisions of 30 CFR part 250. You may use 
applicable provisions of these documents, as approved by the Regional 
Supervisor, for the design, fabrication, and installation of platforms 
such as spars, since standards specifically written for such structures 
do not exist. You may also use alternative codes, rules, or standards, 
as approved by the Regional Supervisor, under the conditions enumerated 
in Sec.  250.141.
    (c) For information on the standards mentioned in this section, and 
where they may be obtained, see Sec.  250.198 of this part.
    (d) The following chart summarizes the applicability of the 
industry standards listed in this section for fixed and floating 
platforms:

------------------------------------------------------------------------
                                                       Applicable to . .
                  Industry standard                            .
------------------------------------------------------------------------
(1) ACI Standard 318-95, Building Code Requirements    Fixed and
 for Reinforced Concrete (ACI 318-95) and Commentary    floating
 (ACI 318R-95),                                         platform, as
                                                        appropriate.
(2) ANSI/AISC 360-05, Specification for Structural     .................
 Steel Buildings;
(3) API Bulletin 2INT-DG, Interim Guidance for Design  .................
 of Offshore Structures for Hurricane Conditions;
(4) API Bulletin 2INT-EX, Interim Guidance for         .................
 Assessment of Existing Offshore Structures for
 Hurricane Conditions;
(5) API Bulletin 2INT-MET, Interim Guidance on         .................
 Hurricane Conditions in the Gulf of Mexico;
(6) API RP 2A-WSD, RP for Planning, Designing, and     .................
 Constructing Fixed Offshore Platforms--Working
 Stress Design;
(7) ASTM Standard C 33-07, approved December 15,       .................
 2007, Standard Specification for Concrete
 Aggregates;
(8) ASTM Standard C 94/C 94M-07, approved January 1,   .................
 2007, Standard Specification for Ready-Mixed
 Concrete;
(9) ASTM Standard C 150-07, approved May 1, 2007,      .................
 Standard Specification for Portland Cement;
(10) ASTM Standard C 330-05, approved December 15,     .................
 2005, Standard Specification for Lightweight
 Aggregates for Structural Concrete;
(11) ASTM Standard C 595-08, approved January 1,       .................
 2008, Standard Specification for Blended Hydraulic
 Cements;
(12) AWS D1.1, Structural Welding Code--Steel;
(13) AWS D1.4, Structural Welding Code--Reinforcing    .................
 Steel;
(14) AWS D3.6M, Specification for Underwater Welding;  .................
(15) NACE Standard RP 0176-2003, Standard Recommended  .................
 Practice (RP), Corrosion Control of Steel Fixed
 Offshore Platforms Associated with Petroleum
 Production;
(16) ACI 357R-84, Guide for the Design and             Fixed platforms.
 Construction of Fixed Offshore Concrete Structures,
 1984; reapproved 1997,
(17) API RP 14J, RP for Design and Hazards Analysis    Floating
 for Offshore Production Facilities;                    platforms.
(18) API RP 2FPS, RP for Planning, Designing, and      .................
 Constructing, Floating Production Systems;
(19) API RP 2RD, Design of Risers for Floating         .................
 Production Systems (FPSs) and Tension-Leg Platforms
 (TLPs);
(20) API RP 2SK, RP for Design and Analysis of         .................
 Station Keeping Systems for Floating Structures;
(21) API RP 2T, RP for Planning, Designing, and        .................
 Constructing Tension Leg Platforms;
(22) API RP 2SM, RP for Design, Manufacture,           .................
 Installation, and Maintenance of Synthetic Fiber
 Ropes for Offshore Mooring;
(23) API RP 2I, In-Service Inspection of Mooring       .................
 Hardware for Floating Drilling Units
------------------------------------------------------------------------

Sec.  250.902  What are the requirements for platform removal and 
location clearance?

    You must remove all structures according to Sec. Sec.  250.1725 
through 250.1730 of Subpart Q--Decommissioning Activities of this part.


Sec.  250.903  What records must I keep?

    (a) You must compile, retain, and make available to BSEE 
representatives for the functional life of all platforms:
    (1) The as-built drawings;
    (2) The design assumptions and analyses;
    (3) A summary of the fabrication and installation nondestructive 
examination records;
    (4) The inspection results from the inspections required by Sec.  
250.919 of this subpart; and
    (5) Records of repairs not covered in the inspection report 
submitted under Sec.  250.919(b).
    (b) You must record and retain the original material test results 
of all primary structural materials during all stages of construction. 
Primary material is material that, should it fail, would lead to a 
significant reduction in platform safety, structural reliability, or 
operating capabilities. Items such as steel brackets, deck stiffeners 
and secondary braces or beams would not generally be considered primary 
structural members (or materials).
    (c) You must provide BSEE with the location of these records in the 
certification statement of your application for platform approval as 
required in Sec.  250.905(j).

Platform Approval Program


Sec.  250.904  What is the Platform Approval Program?

    (a) The Platform Approval Program is the BSEE basic approval 
process for platforms on the OCS. The requirements of the Platform 
Approval Program are described in Sec. Sec.  250.904 through 250.908 of 
this subpart. Completing these requirements will satisfy BSEE criteria 
for approval of fixed platforms of a proven design that will be placed 
in the shallow water areas (<= 400 ft.) of the Gulf of Mexico OCS.
    (b) The requirements of the Platform Approval Program must be met 
by all platforms on the OCS. Additionally, if you want approval for a 
floating platform; a platform of unique design; or a platform being 
installed in deepwater (> 400 ft.) or a frontier area, you must also 
meet the requirements of the

[[Page 64548]]

Platform Verification Program. The requirements of the Platform 
Verification Program are described in Sec. Sec.  250.909 through 
250.918 of this subpart.


Sec.  250.905  How do I get approval for the installation, 
modification, or repair of my platform?

    The Platform Approval Program requires that you submit the 
information, documents, and fee listed in the following table for your 
proposed project. In lieu of submitting the paper copies specified in 
the table, you may submit your application electronically in accordance 
with 30 CFR 250.186(a)(3).

------------------------------------------------------------------------
     Required submittal         Required contents    Other requirements
------------------------------------------------------------------------
(a) Application cover letter  Proposed structure    You must submit
                               designation, lease    three copies. If,
                               number, area, name,   your facility is
                               and block number,     subject to the
                               and the type of       Platform
                               facility your         Verification
                               facility (e.g.,       Program (PVP), you
                               drilling,             must submit four
                               production,           copies.
                               quarters). The
                               structure
                               designation must be
                               unique for the
                               field (some fields
                               are made up of
                               several blocks);
                               i.e. once a
                               platform ``A'' has
                               been used in the
                               field there should
                               never be another
                               platform ``A'' even
                               if the old platform
                               ``A'' has been
                               removed. Single
                               well free standing
                               caissons should be
                               given the same
                               designation as the
                               well. All other
                               structures are to
                               be designated by
                               letter designations.
(b) Location plat...........  Latitude and          Your plat must be
                               longitude             drawn to a scale of
                               coordinates,          1 inch equals 2,000
                               Universal Mercator    feet and include
                               grid-system           the coordinates of
                               coordinates, state    the lease block
                               plane coordinates     boundary lines. You
                               in the Lambert or     must submit three
                               Transverse Mercator   copies.
                               Projection System,
                               and distances in
                               feet from the
                               nearest block
                               lines. These
                               coordinates must be
                               based on the NAD
                               (North American
                               Datum) 27 datum
                               plane coordinate
                               system.
(c) Front, Side, and Plan     Platform dimensions   Your drawing sizes
 View drawings.                and orientation,      must not exceed
                               elevations relative   11'' x 17''. You
                               to M.L.L.W. (Mean     must submit three
                               Lower Low Water),     copies (four copies
                               and pile sizes and    for PVP
                               penetration.          applications).
(d) Complete set of           The approved for      Your drawing sizes
 structural drawings.          construction          must not exceed
                               fabrication           11'' x 17''. You
                               drawings should be    must submit one
                               submitted             copy.
                               including; e.g.,
                               cathodic protection
                               systems; jacket
                               design; pile
                               foundations;
                               drilling,
                               production, and
                               pipeline risers and
                               riser tensioning
                               systems; turrets
                               and turret-and-hull
                               interfaces; mooring
                               and tethering
                               systems;
                               foundations and
                               anchoring systems.
(e) Summary of environmental  A summary of the      You must submit one
 data.                         environmental data    copy.
                               described in the
                               applicable
                               standards
                               referenced under
                               Sec.   250.901(a)
                               of this subpart and
                               in Sec.   250.198
                               of Subpart A, where
                               the data is used in
                               the design or
                               analysis of the
                               platform. Examples
                               of relevant data
                               include information
                               on waves, wind,
                               current, tides,
                               temperature, snow
                               and ice effects,
                               marine growth, and
                               water depth.
(f) Summary of the            Loading information   You must submit one
 engineering design data.      (e.g., live, dead,    copy.
                               environmental),
                               structural
                               information (e.g.,
                               design-life;
                               material types;
                               cathodic protection
                               systems; design
                               criteria; fatigue
                               life; jacket
                               design; deck
                               design; production
                               component design;
                               pile foundations;
                               drilling,
                               production, and
                               pipeline risers and
                               riser tensioning
                               systems; turrets
                               and turret-and-hull
                               interfaces;
                               foundations,
                               foundation pilings
                               and templates, and
                               anchoring systems;
                               mooring or
                               tethering systems;
                               fabrication and
                               installation
                               guidelines), and
                               foundation
                               information (e.g.,
                               soil stability,
                               design criteria).
(g) Project-specific studies  All studies           You must submit one
 used in the platform design   pertinent to          copy of each study.
 or installation.              platform design or
                               installation, e.g.,
                               oceanographic and/
                               or soil reports
                               including the
                               overall site
                               investigative
                               report required in
                               Sec.   250.906.
(h) Description of the loads  Loads imposed by      You must submit one
 imposed on the facility.      jacket; decks;        copy.
                               production
                               components;
                               drilling,
                               production, and
                               pipeline risers,
                               and riser
                               tensioning systems;
                               turrets and turret-
                               and-hull
                               interfaces;
                               foundations,
                               foundation pilings
                               and templates, and
                               anchoring systems;
                               and mooring or
                               tethering systems.

[[Page 64549]]

 
(i) Summary of safety         A summary of          You must submit one
 factors utilized.             pertinent derived     copy.
                               factors of safety
                               against failure for
                               major structural
                               members, e.g.,
                               unity check ratios
                               exceeding 0.85 for
                               steel-jacket
                               platform members,
                               indicated on
                               ``line'' sketches
                               of jacket sections.
(j) A copy of the in-service  This plan is          You must submit one
 inspection plan.              described in Sec.     copy.
                               250.919.
(k) Certification statement.  The following         An authorized
                               statement: ``The      company
                               design of this        representative must
                               structure has been    sign the statement.
                               certified by a        You must submit one
                               recognized            copy.
                               classification
                               society, or a
                               registered civil or
                               structural engineer
                               or equivalent, or a
                               naval architect or
                               marine engineer or
                               equivalent,
                               specializing in the
                               design of offshore
                               structures. The
                               certified design
                               and as-built plans
                               and specifications
                               will be on file at
                               (give location)''.
(l) Payment of the service
 fee listed in Sec.
 250.125.
------------------------------------------------------------------------

Sec.  250.906  What must I do to obtain approval for the proposed site 
of my platform?

    (a) Shallow hazards surveys. You must perform a high-resolution or 
acoustic-profiling survey to obtain information on the conditions 
existing at and near the surface of the seafloor. You must collect 
information through this survey sufficient to determine the presence of 
the following features and their likely effects on your proposed 
platform:
    (1) Shallow faults;
    (2) Gas seeps or shallow gas;
    (3) Slump blocks or slump sediments;
    (4) Shallow water flows;
    (5) Hydrates; or
    (6) Ice scour of seafloor sediments.
    (b) Geologic surveys. You must perform a geological survey relevant 
to the design and siting of your platform. Your geological survey must 
assess:
    (1) Seismic activity at your proposed site;
    (2) Fault zones, the extent and geometry of faulting, and 
attenuation effects of geologic conditions near your site; and
    (3) For platforms located in producing areas, the possibility and 
effects of seafloor subsidence.
    (c) Subsurface surveys. Depending upon the design and location of 
your proposed platform and the results of the shallow hazard and 
geologic surveys, the Regional Supervisor may require you to perform a 
subsurface survey. This survey will include a testing program for 
investigating the stratigraphic and engineering properties of the soil 
that may affect the foundations or anchoring systems for your facility. 
The testing program must include adequate in situ testing, boring, and 
sampling to examine all important soil and rock strata to determine its 
strength classification, deformation properties, and dynamic 
characteristics. If required to perform a subsurface survey, you must 
prepare and submit to the Regional Supervisor a summary report to 
briefly describe the results of your soil testing program, the various 
field and laboratory test methods employed, and the applicability of 
these methods as they pertain to the quality of the samples, the type 
of soil, and the anticipated design application. You must explain how 
the engineering properties of each soil stratum affect the design of 
your platform. In your explanation you must describe the uncertainties 
inherent in your overall testing program, and the reliability and 
applicability of each test method.
    (d) Overall site investigation report. You must prepare and submit 
to the Regional Supervisor an overall site investigation report for 
your platform that integrates the findings of your shallow hazards 
surveys and geologic surveys, and, if required, your subsurface 
surveys. Your overall site investigation report must include analyses 
of the potential for:
    (1) Scouring of the seafloor;
    (2) Hydraulic instability;
    (3) The occurrence of sand waves;
    (4) Instability of slopes at the platform location;
    (5) Liquefaction, or possible reduction of soil strength due to 
increased pore pressures;
    (6) Degradation of subsea permafrost layers;
    (7) Cyclic loading;
    (8) Lateral loading;
    (9) Dynamic loading;
    (10) Settlements and displacements;
    (11) Plastic deformation and formation collapse mechanisms; and
    (12) Soil reactions on the platform foundations or anchoring 
systems.


Sec.  250.907  Where must I locate foundation boreholes?

    (a) For fixed or bottom-founded platforms and tension leg 
platforms, your maximum distance from any foundation pile to a soil 
boring must not exceed 500 feet.
    (b) For deepwater floating platforms which utilize catenary or 
taut-leg moorings, you must take borings at the most heavily loaded 
anchor location, at the anchor points approximately 120 and 240 degrees 
around the anchor pattern from that boring, and, as necessary, other 
points throughout the anchor pattern to establish the soil profile 
suitable for foundation design purposes.


Sec.  250.908  What are the minimum structural fatigue design 
requirements?

    (a) API RP 2A-WSD, Recommended Practice for Planning, Designing and 
Constructing Fixed Offshore Platforms (as incorporated by reference in 
Sec.  250.198), requires that the design fatigue life of each joint and 
member be twice the intended service life of the structure. When 
designing your platform, the following table provides minimum fatigue 
life safety factors for critical structural members and joints.

------------------------------------------------------------------------
                 If . . .                            Then . . .
------------------------------------------------------------------------
(1) There is sufficient structural          The results of the analysis
 redundancy to prevent catastrophic          must indicate a maximum
 failure of the platform or structure        calculated life of twice
 under consideration,                        the design life of the
                                             platform.
(2) There is not sufficient structural      The results of a fatigue
 redundancy to prevent catastrophic          analysis must indicate a
 failure of the platform or structure,       minimum calculated life or
                                             three times the design life
                                             of the platform.

[[Page 64550]]

 
(3) The desirable degree of redundancy is   The results of a fatigue
 significantly reduced as a result of        analysis must indicate a
 fatigue damage,                             minimum calculated life of
                                             three times the design life
                                             of the platform.
------------------------------------------------------------------------

     (b) The documents incorporated by reference in Sec.  250.901 may 
require larger safety factors than indicated in paragraph (a) of this 
section for some key components. When the documents incorporated by 
reference require a larger safety factor than the chart in paragraph 
(a) of this section, the requirements of the incorporated document will 
prevail.

Platform Verification Program


Sec.  250.909  What is the Platform Verification Program?

    The Platform Verification Program is the BSEE approval process for 
ensuring that floating platforms; platforms of a new or unique design; 
platforms in seismic areas; or platforms located in deepwater or 
frontier areas meet stringent requirements for design and construction. 
The program is applied during construction of new platforms and major 
modifications of, or repairs to, existing platforms. These requirements 
are in addition to the requirements of the Platform Approval Program 
described in Sec. Sec.  250.904 through 250.908 of this subpart.


Sec.  250.910  Which of my facilities are subject to the Platform 
Verification Program?

    (a) All new fixed or bottom-founded platforms that meet any of the 
following five conditions are subject to the Platform Verification 
Program:
    (1) Platforms installed in water depths exceeding 400 feet (122 
meters);
    (2) Platforms having natural periods in excess of 3 seconds;
    (3) Platforms installed in areas of unstable bottom conditions;
    (4) Platforms having configurations and designs which have not 
previously been used or proven for use in the area; or
    (5) Platforms installed in seismically active areas.
    (b) All new floating platforms are subject to the Platform 
Verification Program to the extent indicated in the following table:

------------------------------------------------------------------------
                 If . . .                            Then . . .
------------------------------------------------------------------------
(1) Your new floating platform is a         The entire platform is
 buoyant offshore facility that does not     subject to the Platform
 have a ship-shaped hull,                    Verification Program
                                             including the following
                                             associated structures:
                                            (i) Drilling, production,
                                             and pipeline risers, and
                                             riser tensioning systems
                                             (each platform must be
                                             designed to accommodate all
                                             the loads imposed by all
                                             risers and riser does not
                                             have tensioning systems);
                                            (ii) Turrets and turret-and-
                                             hull interfaces;
                                            (iii) Foundations,
                                             foundation pilings and
                                             templates, and anchoring
                                             systems; and
                                            (iv) Mooring or tethering
                                             systems.
(2) Your new floating platform is a         Only the following
 buoyant offshore facility with a ship-      structures that may be
 shaped hull,                                associated with a floating
                                             platform are subject to the
                                             Platform Verification
                                             Program:
                                            (i) Drilling, production,
                                             and pipeline risers, and
                                             riser tensioning systems
                                             (each platform must be
                                             designed to accommodate all
                                             the loads imposed by all
                                             risers and riser tensioning
                                             systems);
                                            (ii) Turrets and turret-and-
                                             hull interfaces;
                                            (iii) Foundations,
                                             foundation pilings and
                                             templates, and anchoring
                                             systems; and
                                            (iv) Mooring or tethering
                                             systems.
------------------------------------------------------------------------

     (c) If a platform is originally subject to the Platform 
Verification Program, then the conversion of that platform at that same 
site for a new purpose, or making a major modification of, or major 
repair to, that platform, is also subject to the Platform Verification 
Program. A major modification includes any modification that increases 
loading on a platform by 10 percent or more. A major repair is a 
corrective operation involving structural members affecting the 
structural integrity of a portion or all of the platform. Before you 
make a major modification or repair to a floating platform, you must 
obtain approval from both the BSEE and the USCG.
    (d) The applicability of Platform Verification Program requirements 
to other types of facilities will be determined by BSEE on a case-by-
case basis.


Sec.  250.911  If my platform is subject to the Platform Verification 
Program, what must I do?

    If your platform, conversion, or major modification or repair meets 
the criteria in Sec.  250.910, you must:
    (a) Design, fabricate, install, use, maintain and inspect your 
platform, conversion, or major modification or repair to your platform 
according to the requirements of this subpart, and the applicable 
documents listed in Sec.  250.901(a) of this subpart;
    (b) Comply with all the requirements of the Platform Approval 
Program found in Sec. Sec.  250.904 through 250.908 of this subpart.
    (c) Submit for the Regional Supervisor's approval three copies each 
of the design verification, fabrication verification, and installation 
verification plans required by Sec.  250.912;
    (d) Submit a complete schedule of all phases of design, 
fabrication, and installation for the Regional Supervisor's approval. 
You must include a project management timeline, Gantt Chart, that 
depicts when interim and final reports required by Sec. Sec.  250.916, 
250.917, and 250.918 will be submitted to the Regional Supervisor for 
each phase. On the timeline, you must break-out the specific scopes of 
work that inherently stand alone (e.g., deck, mooring systems, tendon 
systems, riser systems, turret systems).
    (e) Include your nomination of a Certified Verification Agent (CVA) 
as a part of each verification plan required by Sec.  250.912;
    (f) Follow the additional requirements in Sec. Sec.  250.913 
through 250.918;
    (g) Obtain approval for modifications to approved plans and for 
major deviations from approved installation

[[Page 64551]]

procedures from the Regional Supervisor; and
    (h) Comply with applicable USCG regulations for floating OCS 
facilities.


Sec.  250.912  What plans must I submit under the Platform Verification 
Program?

    If your platform, associated structure, or major modification meets 
the criteria in Sec.  250.910, you must submit the following plans to 
the Regional Supervisor for approval:
    (a) Design verification plan. You may submit your design 
verification plan to BSEE with or subsequent to the submittal of your 
Development and Production Plan (DPP) or Development Operations 
Coordination Document (DOCD) to BOEM. Your design verification must be 
conducted by, or be under the direct supervision of, a registered 
professional civil or structural engineer or equivalent, or a naval 
architect or marine engineer or equivalent, with previous experience in 
directing the design of similar facilities, systems, structures, or 
equipment. For floating platforms, you must ensure that the 
requirements of the USCG for structural integrity and stability, e.g., 
verification of center of gravity, etc., have been met. Your design 
verification plan must include the following:
    (1) All design documentation specified in Sec.  250.905 of this 
subpart;
    (2) Abstracts of the computer programs used in the design process; 
and
    (3) A summary of the major design considerations and the approach 
to be used to verify the validity of these design considerations.
    (b) Fabrication verification plan. The Regional Supervisor must 
approve your fabrication verification plan before you may initiate any 
related operations. Your fabrication verification plan must include the 
following:
    (1) Fabrication drawings and material specifications for artificial 
island structures and major members of concrete-gravity and steel-
gravity structures;
    (2) For jacket and floating structures, all the primary load-
bearing members included in the space-frame analysis; and
    (3) A summary description of the following:
    (i) Structural tolerances;
    (ii) Welding procedures;
    (iii) Material (concrete, gravel, or silt) placement methods;
    (iv) Fabrication standards;
    (v) Material quality-control procedures;
    (vi) Methods and extent of nondestructive examinations for welds 
and materials; and
    (vii) Quality assurance procedures.
    (c) Installation verification plan. The Regional Supervisor must 
approve your installation verification plan before you may initiate any 
related operations. Your installation verification plan must include:
    (1) A summary description of the planned marine operations;
    (2) Contingencies considered;
    (3) Alternative courses of action; and
    (4) An identification of the areas to be inspected. You must 
specify the acceptance and rejection criteria to be used for any 
inspections conducted during installation, and for the post-
installation verification inspection.
    (d) You must combine fabrication verification and installation 
verification plans for manmade islands or platforms fabricated and 
installed in place.


Sec.  250.913  When must I resubmit Platform Verification Program 
plans?

    (a) You must resubmit any design verification, fabrication 
verification, or installation verification plan to the Regional 
Supervisor for approval if:
    (1) The CVA changes;
    (2) The CVA's or assigned personnel's qualifications change; or
    (3) The level of work to be performed changes.
    (b) If only part of a verification plan is affected by one of the 
changes described in paragraph (a) of this section, you can resubmit 
only the affected part. You do not have to resubmit the summary of 
technical details unless you make changes in the technical details.


Sec.  250.914  How do I nominate a CVA?

    (a) As part of your design verification, fabrication verification, 
or installation verification plan, you must nominate a CVA for the 
Regional Supervisor's approval. You must specify whether the nomination 
is for the design, fabrication, or installation phase of verification, 
or for any combination of these phases.
    (b) For each CVA, you must submit a list of documents to be 
forwarded to the CVA, and a qualification statement that includes the 
following:
    (1) Previous experience in third-party verification or experience 
in the design, fabrication, installation, or major modification of 
offshore oil and gas platforms. This should include fixed platforms, 
floating platforms, manmade islands, other similar marine structures, 
and related systems and equipment;
    (2) Technical capabilities of the individual or the primary staff 
for the specific project;
    (3) Size and type of organization or corporation;
    (4) In-house availability of, or access to, appropriate technology. 
This should include computer programs, hardware, and testing materials 
and equipment;
    (5) Ability to perform the CVA functions for the specific project 
considering current commitments;
    (6) Previous experience with BSEE requirements and procedures;
    (7) The level of work to be performed by the CVA.


Sec.  250.915  What are the CVA's primary responsibilities?

    (a) The CVA must conduct specified reviews according to Sec. Sec.  
250.916, 250.917, and 250.918 of this subpart.
    (b) Individuals or organizations acting as CVAs must not function 
in any capacity that would create a conflict of interest, or the 
appearance of a conflict of interest.
    (c) The CVA must consider the applicable provisions of the 
documents listed in Sec.  250.901(a); the alternative codes, rules, and 
standards approved under Sec.  250.901(b); and the requirements of this 
subpart.
    (d) The CVA is the primary contact with the Regional Supervisor and 
is directly responsible for providing immediate reports of all 
incidents that affect the design, fabrication and installation of the 
platform.


Sec.  250.916  What are the CVA's primary duties during the design 
phase?

    (a) The CVA must use good engineering judgment and practices in 
conducting an independent assessment of the design of the platform, 
major modification, or repair. The CVA must ensure that the platform, 
major modification, or repair is designed to withstand the 
environmental and functional load conditions appropriate for the 
intended service life at the proposed location.
    (b) Primary duties of the CVA during the design phase include the 
following:

----------------------------------------------------------------------------------------------------------------
               Type of facility . . .                                     The CVA must . . .
----------------------------------------------------------------------------------------------------------------
(1) For fixed platforms and non-ship-shaped floating  Conduct an independent assessment of all proposed:
 facilities,                                          (i) Planning criteria;
                                                      (ii) Operational requirements;

[[Page 64552]]

 
                                                      (iii) Environmental loading data;
                                                      (iv) Load determinations;
                                                      (v) Stress analyses;
                                                      (vi) Material designations;
                                                      (vii) Soil and foundation conditions;
                                                      (viii) Safety factors; and
                                                      (ix) Other pertinent parameters of the proposed design.
(2) For all floating facilities,                      Ensure that the requirements of the U.S. Coast Guard for
                                                       structural integrity and stability, e.g., verification of
                                                       center of gravity, etc., have been met. The CVA must also
                                                       consider:
                                                      (i) Drilling, production, and pipeline risers, and riser
                                                       tensioning systems;
                                                      (ii) Turrets and turret-and-hull interfaces;
                                                      (iii) Foundations, foundation pilings and templates, and
                                                       anchoring systems; and
                                                      (iv) Mooring or tethering systems.
----------------------------------------------------------------------------------------------------------------

     (c) The CVA must submit interim reports and a final report to the 
Regional Supervisor, and to you, during the design phase in accordance 
with the approved schedule required by Sec.  250.911(d). In each 
interim and final report the CVA must:
    (1) Provide a summary of the material reviewed and the CVA's 
findings;
    (2) In the final CVA report, make a recommendation that the 
Regional Supervisor either accept, request modifications, or reject the 
proposed design unless such a recommendation has been previously made 
in an interim report;
    (3) Describe the particulars of how, by whom, and when the 
independent review was conducted; and
    (4) Provide any additional comments the CVA deems necessary.


Sec.  250.917  What are the CVA's primary duties during the fabrication 
phase?

    (a) The CVA must use good engineering judgment and practices in 
conducting an independent assessment of the fabrication activities. The 
CVA must monitor the fabrication of the platform or major modification 
to ensure that it has been built according to the approved design and 
the fabrication plan. If the CVA finds that fabrication procedures are 
changed or design specifications are modified, the CVA must inform you. 
If you accept the modifications, then the CVA must so inform the 
Regional Supervisor.
    (b) Primary duties of the CVA during the fabrication phase include 
the following:

----------------------------------------------------------------------------------------------------------------
               Type of facility . . .                                     The CVA must . . .
----------------------------------------------------------------------------------------------------------------
(1) For all fixed platforms and non-ship-shaped       Make periodic onsite inspections while fabrication is in
 floating facilities,                                  progress and must verify the following fabrication items,
                                                       as appropriate:
                                                      (i) Quality control by lessee and builder;
                                                      (ii) Fabrication site facilities;
                                                      (iii) Material quality and identification methods;
                                                      (iv) Fabrication procedures specified in the approved
                                                       plan, and adherence to such procedures;
                                                      (v) Welder and welding procedure qualification and
                                                       identification;
                                                      (vi) Structural tolerances specified and adherence to
                                                       those tolerances;
                                                      (vii) The nondestructive examination requirements, and
                                                       evaluation results of the specified examinations;
                                                      (viii) Destructive testing requirements and results;
                                                      (ix) Repair procedures;
                                                      (x) Installation of corrosion-protection systems and
                                                       splash-zone protection;
                                                      (xi) Erection procedures to ensure that overstressing of
                                                       structural members does not occur;
                                                      (xii) Alignment procedures;
                                                      (xiii) Dimensional check of the overall structure,
                                                       including any turrets, turret-and-hull interfaces, any
                                                       mooring line and chain and riser tensioning line
                                                       segments; and
                                                      (xiv) Status of quality-control records at various stages
                                                       of fabrication.
(2) For all floating facilities,                      Ensure that the requirements of the U.S. Coast Guard
                                                       floating for structural integrity and stability, e.g.,
                                                       verification of center of gravity, etc., have been met.
                                                       The CVA must also consider:
                                                      (i) Drilling, production, and pipeline risers, and riser
                                                       tensioning systems (at least for the initial fabrication
                                                       of these elements);
                                                      (ii) Turrets and turret-and-hull interfaces;
                                                      (iii) Foundation pilings and templates, and anchoring
                                                       systems; and
                                                      (iv) Mooring or tethering systems.
----------------------------------------------------------------------------------------------------------------

     (c) The CVA must submit interim reports and a final report to the 
Regional Supervisor, and to you, during the fabrication phase in 
accordance with the approved schedule required by Sec.  250.911(d). In 
each interim and final report the CVA must:
    (1) Give details of how, by whom, and when the independent 
monitoring activities were conducted;
    (2) Describe the CVA's activities during the verification process;
    (3) Summarize the CVA's findings;
    (4) Confirm or deny compliance with the design specifications and 
the approved fabrication plan;
    (5) In the final CVA report, make a recommendation to accept or 
reject the fabrication unless such a recommendation has been previously 
made in an interim report; and
    (6) Provide any additional comments that the CVA deems necessary.


Sec.  250.918  What are the CVA's primary duties during the 
installation phase?

    (a) The CVA must use good engineering judgment and practice in

[[Page 64553]]

conducting an independent assessment of the installation activities.
    (b) Primary duties of the CVA during the installation phase include 
the following:

----------------------------------------------------------------------------------------------------------------
                 The CVA must . . .                          Operation or equipment to be inspected . . .
----------------------------------------------------------------------------------------------------------------
(1) Verify, as appropriate,                           (i) Loadout and initial flotation operations;
                                                      (ii) Towing operations to the specified location, and
                                                       review the towing records;
                                                      (iii) Launching and uprighting operations;
                                                      (iv) Submergence operations;
                                                      (v) Pile or anchor installations;
                                                      (vi) Installation of mooring and tethering systems;
                                                      (vii) Final deck and component installations; and
                                                      (viii) Installation at the approved location according to
                                                       the approved design and the installation plan.
(2) Witness (for a fixed or floating platform),       (i) The loadout of the jacket, decks, piles, or structures
                                                       from each fabrication site;
                                                      (ii) The actual installation of the platform or major
                                                       modification and the related installation activities.
(3) Witness (for a floating platform),                (i) The loadout of the platform;
                                                      (ii) The installation of drilling, production, and
                                                       pipeline risers, and riser tensioning systems (at least
                                                       for the initial installation of these elements);
                                                      (iii) The installation of turrets and turret-and-hull
                                                       interfaces;
                                                      (iv) The installation of foundation pilings and templates,
                                                       and anchoring systems; and
                                                      (v) The installation of the mooring and tethering systems.
(4) Conduct an onsite survey,                         Survey the platform after transportation to the approved
                                                       location.
(5) Spot-check as necessary to determine compliance   (i) Equipment;
 with the applicable documents listed in Sec.         (ii) Procedures; and
 250.901(a); the alternative codes, rules and         (iii) Recordkeeping.
 standards approved under Sec.   250.901(b); the
 requirements listed in Sec.   250.903 and Sec.
 Sec.   250.906 through 250.908 of this subpart and
 the approved plans,
----------------------------------------------------------------------------------------------------------------

     (c) The CVA must submit interim reports and a final report to the 
Regional Supervisor, and to you, during the installation phase in 
accordance with the approved schedule required by Sec.  250.911(d). In 
each interim and final report the CVA must:
    (1) Give details of how, by whom, and when the independent 
monitoring activities were conducted;
    (2) Describe the CVA's activities during the verification process;
    (3) Summarize the CVA's findings;
    (4) Confirm or deny compliance with the approved installation plan;
    (5) In the final report, make a recommendation to accept or reject 
the installation unless such a recommendation has been previously made 
in an interim report; and
    (6) Provide any additional comments that the CVA deems necessary.

Inspection, Maintenance, and Assessment of Platforms


Sec.  250.919  What in-service inspection requirements must I meet?

    (a) You must submit a comprehensive in-service inspection report 
annually by November 1 to the Regional Supervisor that must include:
    (1) A list of fixed and floating platforms you inspected in the 
preceding 12 months;
    (2) The extent and area of inspection for both the above-water and 
underwater portions of the platform and the pertinent components of the 
mooring system for floating platforms;
    (3) The type of inspection employed (e.g., visual, magnetic 
particle, ultrasonic testing);
    (4) The overall structural condition of each platform, including a 
corrosion protection evaluation; and
    (5) A summary of the inspection results indicating what repairs, if 
any, were needed.
    (b) If any of your structures have been exposed to a natural 
occurrence (e.g., hurricane, earthquake, or tropical storm), the 
Regional Supervisor may require you to submit an initial report of all 
structural damage, followed by subsequent updates, which include the 
following:
    (1) A list of affected structures;
    (2) A timetable for conducting the inspections described in section 
14.4.3 of API RP 2A-WSD (as incorporated by reference in Sec.  
250.198); and
    (3) An inspection plan for each structure that describes the work 
you will perform to determine the condition of the structure.
    (c) The Regional Supervisor may also require you to submit the 
results of the inspections referred to in paragraph (b)(2) of this 
section, including a description of any detected damage that may 
adversely affect structural integrity, an assessment of the structure's 
ability to withstand any anticipated environmental conditions, and any 
remediation plans. Under Sec. Sec.  250.900(b)(3) and 250.905, you must 
obtain approval from BSEE before you make major repairs of any damage 
unless you meet the requirements of Sec.  250.900(c).


Sec.  250.920  What are the BSEE requirements for assessment of fixed 
platforms?

    (a) You must document all wells, equipment, and pipelines supported 
by the platform if you intend to use either the A-2 or A-3 assessment 
category. Assessment categories are defined in API RP 2A-WSD, Section 
17.3 (as incorporated by reference in Sec.  250.198). If BSEE objects 
to the assessment category you used for your assessment, you may need 
to redesign and/or modify the platform to adequately demonstrate that 
the platform is able to withstand the environmental loadings for the 
appropriate assessment category.
    (b) You must perform an analysis check when your platform will have 
additional personnel, additional topside facilities, increased 
environmental or operational loading, or inadequate deck height your 
platform suffered significant damage (e.g., experienced damage to 
primary structural members or conductor guide trays or global 
structural integrity is adversely affected); or the exposure category 
changes to a more restrictive level (see Sections 17.2.1 through 17.2.5 
of API RP 2A-WSD, incorporated by reference in

[[Page 64554]]

Sec.  250.198, for a description of assessment initiators).
    (c) You must initiate mitigation actions for platforms that do not 
pass the assessment process of API RP 2A-WSD. You must submit 
applications for your mitigation actions (e.g., repair, modification, 
decommissioning) to the Regional Supervisor for approval before you 
conduct the work.
    (d) The BSEE may require you to conduct a platform design basis 
check when the reduced environmental loading criteria contained in API 
RP 2A-WSD Section 17.6 are not applicable.
    (e) By November 1, 2009, you must submit a complete list of all the 
platforms you operate, together with all the appropriate data to 
support the assessment category you assign to each platform and the 
platform assessment initiators (as defined in API RP 2A-WSD) to the 
Regional Supervisor. You must submit subsequent complete lists and the 
appropriate data to support the consequence-of-failure category every 5 
years thereafter, or as directed by the Regional Supervisor.
    (f) The use of Section 17, Assessment of Existing Platforms, of API 
RP 2A-WSD is limited to existing fixed structures that are serving 
their original approved purpose. You must obtain approval from the 
Regional Supervisor for any change in purpose of the platform, 
following the provisions of API RP 2A-WSD, Section 15, Re-use.


Sec.  250.921  How do I analyze my platform for cumulative fatigue?

    (a) If you are required to analyze cumulative fatigue on your 
platform because of the results of an inspection or platform 
assessment, you must ensure that the safety factors for critical 
elements listed in Sec.  250.908 are met or exceeded.
    (b) If the calculated life of a joint or member does not meet the 
criteria of Sec.  250.908, you must either mitigate the load, 
strengthen the joint or member, or develop an increased inspection 
process.

Subpart J--Pipelines and Pipeline Rights-of-Way


Sec.  250.1000  General requirements.

    (a) Pipelines and associated valves, flanges, and fittings shall be 
designed, installed, operated, maintained, and abandoned to provide 
safe and pollution-free transportation of fluids in a manner which does 
not unduly interfere with other uses in the Outer Continental Shelf 
(OCS).
    (b) An application must be accompanied by payment of the service 
fee listed in Sec.  250.125 and submitted to the Regional Supervisor 
and approval obtained before:
    (1) Installation, modification, or abandonment of a lease term 
pipeline;
    (2) Installation or modification of a right-of-way (other than 
lease term) pipeline; or
    (3) Modification or relinquishment of a pipeline right-of way.
    (c)(1) Department of the Interior (DOI) pipelines, as defined in 
Sec.  250.1001, must meet the requirements in Sec. Sec.  250.1000 
through 250.1008.
    (2) A pipeline right-of-way grant holder must identify in writing 
to the Regional Supervisor the operator of any pipeline located on its 
right-of-way, if the operator is different from the right-of-way grant 
holder.
    (3) A producing operator must identify for its own records, on all 
existing pipelines located on its lease or right-of-way, the specific 
points at which operating responsibility transfers to a transporting 
operator.
    (i) Each producing operator must, if practical, durably mark all of 
its above-water transfer points by April 14, 1999, or the date a 
pipeline begins service, whichever is later.
    (ii) If it is not practical to durably mark a transfer point, and 
the transfer point is located above water, then the operator must 
identify the transfer point on a schematic located on the facility.
    (iii) If a transfer point is located below water, then the operator 
must identify the transfer point on a schematic and provide the 
schematic to BSEE upon request.
    (iv) If adjoining producing and transporting operators cannot agree 
on a transfer point by April 14, 1999, the BSEE Regional Supervisor and 
the Department of Transportation (DOT) Office of Pipeline Safety (OPS) 
Regional Director may jointly determine the transfer point.
    (4) The transfer point serves as a regulatory boundary. An operator 
may write to the BSEE Regional Supervisor to request an exception to 
this requirement for an individual facility or area. The Regional 
Supervisor, in consultation with the OPS Regional Director and affected 
parties, may grant the request.
    (5) Pipeline segments designed, constructed, maintained, and 
operated under DOT regulations but transferring to DOI regulation as of 
October 16, 1998, may continue to operate under DOT design and 
construction requirements until significant modifications or repairs 
are made to those segments. After October 16, 1998, BSEE operational 
and maintenance requirements will apply to those segments.
    (6) Any producer operating a pipeline that crosses into State 
waters without first connecting to a transporting operator's facility 
on the OCS must comply with this subpart. Compliance must extend from 
the point where hydrocarbons are first produced, through and including 
the last valve and associated safety equipment (e.g., pressure safety 
sensors) on the last production facility on the OCS.
    (7) Any producer operating a pipeline that connects facilities on 
the OCS must comply with this subpart.
    (8) Any operator of a pipeline that has a valve on the OCS 
downstream (landward) of the last production facility may ask in 
writing that the BSEE Regional Supervisor recognize that valve as the 
last point BSEE will exercise its regulatory authority.
    (9) A pipeline segment is not subject to BSEE regulations for 
design, construction, operation, and maintenance if:
    (i) It is downstream (generally shoreward) of the last valve and 
associated safety equipment on the last production facility on the OCS; 
and
    (ii) It is subject to regulation under 49 CFR parts 192 and 195.
    (10) DOT may inspect all upstream safety equipment (including 
valves, over-pressure protection devices, cathodic protection 
equipment, and pigging devices, etc.) that serve to protect the 
integrity of DOT-regulated pipeline segments.
    (11) OCS pipeline segments not subject to DOT regulation under 49 
CFR parts 192 and 195 are subject to all BSEE regulations.
    (12) A producer may request that its pipeline operate under DOT 
regulations governing pipeline design, construction, operation, and 
maintenance.
    (i) The operator's request must be in the form of a written 
petition to the BSEE Regional Supervisor that states the justification 
for the pipeline to operate under DOT regulation.
    (ii) The Regional Supervisor will decide, on a case-by-case basis, 
whether to grant the operator's request. In considering each petition, 
the Regional Supervisor will consult with the Office of Pipeline Safety 
(OPS) Regional Director.
    (13) A transporter who operates a pipeline regulated by DOT may 
request to operate under BSEE regulations governing pipeline operation 
and maintenance. Any subsequent repairs or modifications will also be 
subject to BSEE regulations governing design and construction.
    (i) The operator's request must be in the form of a written 
petition to the OPS

[[Page 64555]]

Regional Director and the BSEE Regional Supervisor.
    (ii) The BSEE Regional Supervisor and the OPS Regional Director 
will decide how to act on this petition.
    (d) A pipeline which qualifies as a right-of-way pipeline (see 
Sec.  250.1001, Definitions) shall not be installed until a right-of-
way has been requested and granted in accordance with this subpart.
    (e)(1) The Regional Supervisor may suspend any pipeline operation 
upon a determination by the Regional Supervisor that continued activity 
would threaten or result in serious, irreparable, or immediate harm or 
damage to life (including fish and other aquatic life), property, 
mineral deposits, or the marine, coastal, or human environment.
    (2) The Regional Supervisor may also suspend pipeline operations or 
a right-of-way grant if the Regional Supervisor determines that the 
lessee or right-of-way holder has failed to comply with a provision of 
the Act or any other applicable law, a provision of these or other 
applicable regulations, or a condition of a permit or right-of-way 
grant.
    (3) The Secretary of the Interior (Secretary) may cancel a pipeline 
permit or right-of-way grant in accordance with 43 U.S.C. 1334(a)(2). A 
right-of-way grant may be forfeited in accordance with 43 U.S.C. 
1334(e).


Sec.  250.1001  Definitions.

    Terms used in this subpart shall have the meanings given below:
    DOI pipelines include:
    (1) Producer-operated pipelines extending upstream (generally 
seaward) from each point on the OCS at which operating responsibility 
transfers from a producing operator to a transporting operator;
    (2) Producer-operated pipelines extending upstream (generally 
seaward) of the last valve (including associated safety equipment) on 
the last production facility on the OCS that do not connect to a 
transporter-operated pipeline on the OCS before crossing into State 
waters;
    (3) Producer-operated pipelines connecting production facilities on 
the OCS;
    (4) Transporter-operated pipelines that DOI and DOT have agreed are 
to be regulated as DOI pipelines; and
    (5) All OCS pipelines not subject to regulation under 49 CFR parts 
192 and 195.
    DOT pipelines include:
    (1) Transporter-operated pipelines currently operated under DOT 
requirements governing design, construction, maintenance, and 
operation;
    (2) Producer-operated pipelines that DOI and DOT have agreed are to 
be regulated under DOT requirements governing design, construction, 
maintenance, and operation; and
    (3) Producer-operated pipelines downstream (generally shoreward) of 
the last valve (including associated safety equipment) on the last 
production facility on the OCS that do not connect to a transporter-
operated pipeline on the OCS before crossing into State waters and that 
are regulated under 49 CFR parts 192 and 195.
    Lease term pipelines are those pipelines owned and operated by a 
lessee or operator and are wholly contained within the boundaries of a 
single lease, unitized leases, or contiguous (not cornering) leases of 
that lessee or operator.
    Out-of-service pipelines are those pipelines that have not been 
used to transport oil, natural gas, sulfur, or produced water for more 
than 30 consecutive days.
    Pipelines are the piping, risers, and appurtenances installed for 
the purpose of transporting oil, gas, sulphur, and produced water. 
(Piping confined to a production platform or structure is covered in 
Subpart H, Production Safety Systems, and is excluded from this 
subpart.)
    Production facilities means OCS facilities that receive hydrocarbon 
production either directly from wells or from other facilities that 
produce hydrocarbons from wells. They may include processing equipment 
for treating the production or separating it into its various liquid 
and gaseous components before transporting it to shore.
    Right-of-way pipelines are those pipelines which--
    (1) Are contained within the boundaries of a single lease or group 
of unitized leases but are not owned and operated by the lessee or 
operator of that lease or unit,
    (2) Are contained within the boundaries of contiguous (not 
cornering) leases which do not have a common lessee or operator,
    (3) Are contained within the boundaries of contiguous (not 
cornering) leases which have a common lessee or operator but are not 
owned and operated by that common lessee or operator, or
    (4) Cross any portion of an unleased block(s).


Sec.  250.1002  Design requirements for DOI pipelines.

    (a) The internal design pressure for steel pipe shall be determined 
in accordance with the following formula:
[GRAPHIC] [TIFF OMITTED] TR18OC11.000

    For limitations see section 841.121 of American National Standards 
Institute (ANSI) B31.8 (as incorporated by reference in Sec.  250.198) 
where--

P = Internal design pressure in pounds per square inch (psi).
S = Specified minimum yield strength, in psi, stipulated in the 
specification under which the pipe was purchased from the 
manufacturer or determined in accordance with section 811.253(h) of 
ANSI B31.8.
D = Nominal outside diameter of pipe, in inches.
t = Nominal wall thickness, in inches.
F = Construction design factor of 0.72 for the submerged component 
and 0.60 for the riser component.
E = Longitudinal joint factor obtained from Table 841.1B of ANSI 
B31.8 (see also section 811.253(d)).
T = Temperature derating factor obtained from Table 841.1C of ANSI 
B31.8.

    (b)(1) Pipeline valves shall meet the minimum design requirements 
of American Petroleum Institute (API) Spec 6A (as incorporated by 
reference in Sec.  250.198), API Spec 6D (as incorporated by reference 
in Sec.  250.198), or the equivalent. A valve may not be used under 
operating conditions that exceed the applicable pressure-temperature 
ratings contained in those standards.
    (2) Pipeline flanges and flange accessories shall meet the minimum 
design requirements of ANSI B16.5, API Spec 6A, or the equivalent (as 
incorporated by reference in 30 CFR 250.198). Each flange assembly must 
be able to withstand the maximum pressure at which the pipeline is to 
be operated and to maintain its physical and chemical properties at any 
temperature to which it is anticipated that it might be subjected in 
service.
    (3) Pipeline fittings shall have pressure-temperature ratings based 
on stresses for pipe of the same or equivalent material. The actual 
bursting strength of the fitting shall at least be equal to the 
computed bursting strength of the pipe.
    (4) If you are installing pipelines constructed of unbonded 
flexible pipe, you must design them according to the standards and 
procedures of API Spec 17J, as incorporated by reference in 30 CFR 
250.198.
    (5) You must design pipeline risers for tension leg platforms and 
other floating platforms according to the design standards of API RP 
2RD, Design of Risers for Floating Production Systems (FPSs) and 
Tension Leg Platforms (TLPs) (as incorporated by reference in Sec.  
250.198).

[[Page 64556]]

    (c) The maximum allowable operating pressure (MAOP) shall not 
exceed the least of the following:
    (1) Internal design pressure of the pipeline, valves, flanges, and 
fittings;
    (2) Eighty percent of the hydrostatic pressure test (HPT) pressure 
of the pipeline; or
    (3) If applicable, the MAOP of the receiving pipeline when the 
proposed pipeline and the receiving pipeline are connected at a subsea 
tie-in.
    (d) If the maximum source pressure (MSP) exceeds the pipeline's 
MAOP, you must install and maintain redundant safety devices meeting 
the requirements of section A9 of API RP 14C (as incorporated by 
reference in Sec.  250.198). Pressure safety valves (PSV) may be used 
only after a determination by the Regional Supervisor that the pressure 
will be relieved in a safe and pollution-free manner. The setting level 
at which the primary and redundant safety equipment actuates shall not 
exceed the pipeline's MAOP.
    (e) Pipelines shall be provided with an external protective coating 
capable of minimizing underfilm corrosion and a cathodic protection 
system designed to mitigate corrosion for at least 20 years.
    (f) Pipelines shall be designed and maintained to mitigate any 
reasonably anticipated detrimental effects of water currents, storm or 
ice scouring, soft bottoms, mud slides, earthquakes, subfreezing 
temperatures, and other environmental factors.


Sec.  250.1003  Installation, testing, and repair requirements for DOI 
pipelines.

    (a)(1) Pipelines greater than 8\5/8\ inches in diameter and 
installed in water depths of less than 200 feet shall be buried to a 
depth of at least 3 feet unless they are located in pipeline congested 
areas or seismically active areas as determined by the Regional 
Supervisor. Nevertheless, the Regional Supervisor may require burial of 
any pipeline if the Regional Supervisor determines that such burial 
will reduce the likelihood of environmental degradation or that the 
pipeline may constitute a hazard to trawling operations or other uses. 
A trawl test or diver survey may be required to determine whether or 
not pipeline burial is necessary or to determine whether a pipeline has 
been properly buried.
    (2) Pipeline valves, taps, tie-ins, capped lines, and repaired 
sections that could be obstructive shall be provided with at least 3 
feet of cover unless the Regional Supervisor determines that such items 
present no hazard to trawling or other operations. A protective device 
may be used to cover an obstruction in lieu of burial if it is approved 
by the Regional Supervisor prior to installation.
    (3) Pipelines shall be installed with a minimum separation of 18 
inches at pipeline crossings and from obstructions.
    (4) Pipeline risers installed after April 1, 1988, shall be 
protected from physical damage that could result from contact with 
floating vessels. Riser protection on pipelines installed on or before 
April 1, 1988, may be required when the Regional Supervisor determines 
that significant damage potential exists.
    (b)(1) Pipelines shall be pressure tested with water at a 
stabilized pressure of at least 1.25 times the MAOP for at least 8 
hours when installed, relocated, uprated, or reactivated after being 
out-of-service for more than 1 year.
    (2) Prior to returning a pipeline to service after a repair, the 
pipeline shall be pressure tested with water or processed natural gas 
at a minimum stabilized pressure of at least 1.25 times the MAOP for at 
least 2 hours.
    (3) Pipelines shall not be pressure tested at a pressure which 
produces a stress in the pipeline in excess of 95 percent of the 
specified minimum-yield strength of the pipeline. A temperature 
recorder measuring test fluid temperature synchronized with a pressure 
recorder along with deadweight test readings shall be employed for all 
pressure testing. When a pipeline is pressure tested, no observable 
leakage shall be allowed. Pressure gauges and recorders shall be of 
sufficient accuracy to verify that leakage is not occurring.
    (4) The Regional Supervisor may require pressure testing of 
pipelines to verify the integrity of the system when the Regional 
Supervisor determines that there is a reasonable likelihood that the 
line has been damaged or weakened by external or internal conditions.
    (c) When a pipeline is repaired utilizing a clamp, the clamp shall 
be a full encirclement clamp able to withstand the anticipated pipeline 
pressure.


Sec.  250.1004  Safety equipment requirements for DOI pipelines.

    (a) The lessee shall ensure the proper installation, operation, and 
maintenance of safety devices required by this section on all incoming, 
departing, and crossing pipelines on platforms.
    (b)(1)(i) Incoming pipelines to a platform shall be equipped with a 
flow safety valve (FSV).
    (ii) For sulphur operations, incoming pipelines delivering gas to 
the power plant platform may be equipped with high- and low-pressure 
sensors (PSHL), which activate audible and visual alarms in lieu of 
requirements in paragraph (b)(1)(i) of this section. The PSHL shall be 
set at 15 percent or 5 psi, whichever is greater, above and below the 
normal operating pressure range.
    (2) Incoming pipelines boarding a production platform shall be 
equipped with an automatic shutdown valve (SDV) immediately upon 
boarding the platform. The SDV shall be connected to the automatic- and 
remote-emergency shut-in systems.
    (3) Departing pipelines receiving production from production 
facilities shall be protected by high- and low-pressure sensors (PSHL) 
to directly or indirectly shut in all production facilities. The PSHL 
shall be set not to exceed 15 percent above and below the normal 
operating pressure range. However, high pilots shall not be set above 
the pipeline's MAOP.
    (4) Crossing pipelines on production or manned nonproduction 
platforms which do not receive production from the platform shall be 
equipped with an SDV immediately upon boarding the platform. The SDV 
shall be operated by a PSHL on the departing pipelines and connected to 
the platform automatic- and remote-emergency shut-in systems.
    (5) The Regional Supervisor may require that oil pipelines be 
equipped with a metering system to provide a continuous volumetric 
comparison between the input to the line at the structure(s) and the 
deliveries onshore. The system shall include an alarm system and shall 
be of adequate sensitivity to detect variations between input and 
discharge volumes. In lieu of the foregoing, a system capable of 
detecting leaks in the pipeline may be substituted with the approval of 
the Regional Supervisor.
    (6) Pipelines incoming to a subsea tie-in shall be equipped with a 
block valve and an FSV. Bidirectional pipelines connected to a subsea 
tie-in shall be equipped with only a block valve.
    (7) Gas-lift or water-injection pipelines on unmanned platforms 
need only be equipped with an FSV installed immediately upstream of 
each casing annulus or the first inlet valve on the christmas tree.
    (8) Bidirectional pipelines shall be equipped with a PSHL and an 
SDV immediately upon boarding each platform.
    (9) Pipeline pumps must comply with section A7 of API RP 14C (as 
incorporated by reference in Sec.  250.198). The setting levels for the 
PSHL devices are specified in paragraph (b)(3) of this section.

[[Page 64557]]

    (c) If the required safety equipment is rendered ineffective or 
removed from service on pipelines which are continued in operation, an 
equivalent degree of safety shall be provided. The safety equipment 
shall be identified by the placement of a sign on the equipment stating 
that the equipment is rendered ineffective or removed from service.


Sec.  250.1005  Inspection requirements for DOI pipelines.

    (a) Pipeline routes shall be inspected at time intervals and 
methods prescribed by the Regional Supervisor for indication of 
pipeline leakage. The results of these inspections shall be retained 
for at least 2 years and be made available to the Regional Supervisor 
upon request.
    (b) When pipelines are protected by rectifiers or anodes for which 
the initial life expectancy of the cathodic protection system either 
cannot be calculated or calculations indicate a life expectancy of less 
than 20 years, such pipelines shall be inspected annually by taking 
measurements of pipe-to-electrolyte potential.


Sec.  250.1006  How must I decommission and take out of service a DOI 
pipeline?

    (a) The requirements for decommissioning pipelines are listed in 
Sec.  250.1750 through Sec.  250.1754.
    (b) The table in this section lists the requirements if you take a 
DOI pipeline out of service:

----------------------------------------------------------------------------------------------------------------
    If you have the pipeline out of service for:                            Then you must:
----------------------------------------------------------------------------------------------------------------
(1) 1 year or less,                                   Isolate the pipeline with a blind flange or a closed block
                                                       valve at each end of the pipeline.
(2) More than 1 year but less than 5 years,           Flush and fill the pipeline with inhibited seawater.
(3) 5 or more years,                                  Decommission the pipeline according to Sec.  Sec.
                                                       250.1750-250.1754.
----------------------------------------------------------------------------------------------------------------

Sec.  250.1007  What to include in applications.

    (a) Applications to install a lease term pipeline or for a pipeline 
right-of-way grant must be submitted in quadruplicate to the Regional 
Supervisor. Right-of-way grant applications must include an 
identification of the operator of the pipeline. Each application must 
include the following:
    (1) Plat(s) drawn to a scale specified by the Regional Supervisor 
showing major features and other pertinent data including area, lease, 
and block designations; water depths; route; length in Federal waters; 
width of right-of-way, if applicable; connecting facilities; size; 
product(s) to be transported with anticipated gravity or density; 
burial depth; direction of flow; X-Y coordinates of key points; and the 
location of other pipelines that will be connected to or crossed by the 
proposed pipeline(s). The initial and terminal points of the pipeline 
and any continuation into State jurisdiction shall be accurately 
located even if the pipeline is to have an onshore terminal point. A 
plat(s) submitted for a pipeline right-of-way shall bear a signed 
certificate upon its face by the engineer who made the map that 
certifies that the right-of-way is accurately represented upon the map 
and that the design characteristics of the associated pipeline are in 
accordance with applicable regulations.
    (2) A schematic drawing showing the size, weight, grade, wall 
thickness, and type of line pipe and risers; pressure-regulating 
devices (including back-pressure regulators); sensing devices with 
associated pressure-control lines; PSV's and settings; SDV's, FSV's, 
and block valves; and manifolds. This schematic drawing shall also show 
input source(s), e.g., wells, pumps, compressors, and vessels; maximum 
input pressure(s); the rated working pressure, as specified by ANSI or 
API, of all valves, flanges, and fittings; the initial receiving 
equipment and its rated working pressure; and associated safety 
equipment and pig launchers and receivers. The schematic must indicate 
the point on the OCS at which operating responsibility transfers 
between a producing operator and a transporting operator.
    (3) General information as follows:
    (i) Description of cathodic protection system. If pipeline anodes 
are to be used, specify the type, size, weight, number, spacing, and 
anticipated life;
    (ii) Description of external pipeline coating system;
    (iii) Description of internal protective measures;
    (iv) Specific gravity of the empty pipe;
    (v) MSP;
    (vi) MAOP and calculations used in its determination;
    (vii) Hydrostatic test pressure, medium, and period of time that 
the line will be tested;
    (viii) MAOP of the receiving pipeline or facility,
    (ix) Proposed date for commencing installation and estimated time 
for construction; and
    (x) Type of protection to be afforded crossing pipelines, subsea 
valves, taps, and manifold assemblies, if applicable.
    (4) A description of any additional design precautions you took to 
enable the pipeline to withstand the effects of water currents, storm 
or ice scouring, soft bottoms, mudslides, earthquakes, permafrost, and 
other environmental factors.
    (i) If you propose to use unbonded flexible pipe, your application 
must include:
    (A) The manufacturer's design specification sheet;
    (B) The design pressure (psi);
    (C) An identification of the design standards you used; and
    (D) A review by a third-party independent verification agent (IVA) 
according to API Spec 17J (as incorporated by reference in Sec.  
250.198), if applicable.
    (ii) If you propose to use one or more pipeline risers for a 
tension leg platform or other floating platform, your application must 
include:
    (A) The design fatigue life of the riser, with calculations, and 
the fatigue point at which you would replace the riser;
    (B) The results of your vortex-induced vibration (VIV) analysis;
    (C) An identification of the design standards you used; and
    (D) A description of any necessary mitigation measures such as the 
use of helical strakes or anchoring devices.
    (5) The application shall include a shallow hazards survey report 
and, if required by the Regional Director, an archaeological resource 
report that covers the entire length of the pipeline. A shallow hazards 
analysis may be included in a lease term pipeline application in lieu 
of the shallow hazards survey report with the approval of the Regional 
Director. The Regional Director may require the submission of the data 
upon which the report or analysis is based.
    (b) Applications to modify an approved lease term pipeline or 
right-of-way grant shall be submitted in quadruplicate to the Regional 
Supervisor. These applications need only address those items in the 
original application affected by the proposed modification.


Sec.  250.1008  Reports.

    (a) The lessee, or right-of-way holder, shall notify the Regional 
Supervisor at

[[Page 64558]]

least 48 hours prior to commencing the installation or relocation of a 
pipeline or conducting a pressure test on a pipeline.
    (b) The lessee or right-of-way holder shall submit a report to the 
Regional Supervisor within 90 days after completion of any pipeline 
construction. The report, submitted in triplicate, shall include an 
``as-built'' location plat drawn to a scale specified by the Regional 
Supervisor showing the location, length in Federal waters, and X-Y 
coordinates of key points; the completion date; the proposed date of 
first operation; and the HPT data. Pipeline right-of-way ``as-built'' 
location plats shall be certified by a registered engineer or land 
surveyor and show the boundaries of the right-of-way as granted. If 
there is a substantial deviation of the pipeline route as granted in 
the right-of-way, the report shall include a discussion of the reasons 
for such deviation.
    (c) The lessee or right-of-way holder shall report to the Regional 
Supervisor any pipeline taken out of service. If the period of time in 
which the pipeline is out of service is greater than 60 days, written 
confirmation is also required.
    (d) The lessee or right-of-way holder shall report to the Regional 
Supervisor when any required pipeline safety equipment is taken out of 
service for more than 12 hours. The Regional Supervisor shall be 
notified when the equipment is returned to service.
    (e) The lessee or right-of-way holder must notify the Regional 
Supervisor before the repair of any pipeline or as soon as practicable. 
Your notification must be accompanied by payment of the service fee 
listed in Sec.  250.125. You must submit a detailed report of the 
repair of a pipeline or pipeline component to the Regional Supervisor 
within 30 days after the completion of the repairs. In the report you 
must include the following:
    (1) Description of repairs;
    (2) Results of pressure test; and
    (3) Date returned to service.
    (f) The Regional Supervisor may require that DOI pipeline failures 
be analyzed and that samples of a failed section be examined in a 
laboratory to assist in determining the cause of the failure. A 
comprehensive written report of the information obtained shall be 
submitted by the lessee to the Regional Supervisor as soon as 
available.
    (g) If the effects of scouring, soft bottoms, or other 
environmental factors are observed to be detrimentally affecting a 
pipeline, a plan of corrective action shall be submitted to the 
Regional Supervisor for approval within 30 days of the observation. A 
report of the remedial action taken shall be submitted to the Regional 
Supervisor by the lessee or right-of-way holder within 30 days after 
completion.
    (h) The results and conclusions of measurements of pipe-to-
electrolyte potential measurements taken annually on DOI pipelines in 
accordance with Sec.  250.1005(b) of this part shall be submitted to 
the Regional Supervisor by the lessee before March of each year.


Sec.  250.1009  Requirements to obtain pipeline right-of-way grants.

    (a) In addition to applicable requirements of Sec. Sec.  250.1000 
through 250.1008 and other regulations of this part, regulations of the 
Department of Transportation, Department of the Army, and the Federal 
Energy Regulatory Commission (FERC), when a pipeline qualifies as a 
right-of-way pipeline, the pipeline shall not be installed until a 
right-of-way has been requested and granted in accordance with this 
subpart. The right-of-way grant is issued pursuant to 43 U.S.C. 1334(e) 
and may be acquired and held only by citizens and nationals of the 
United States; aliens lawfully admitted for permanent residence in the 
United States as defined in 8 U.S.C. 1101(a)(20); private, public, or 
municipal corporations organized under the laws of the United States or 
territory thereof, the District of Columbia, or of any State; or 
associations of such citizens, nationals, resident aliens, or private, 
public, or municipal corporations, States, or political subdivisions of 
States.
    (b) A right-of-way shall include the site on which the pipeline and 
associated structures are to be situated, shall not exceed 200 feet in 
width unless safety and environmental factors during construction and 
operation of the associated right-of-way pipeline require a greater 
width, and shall be limited to the area reasonably necessary for 
pumping stations or other accessory structures.


Sec.  250.1010  General requirements for pipeline right-of-way holders.

    An applicant, by accepting a right-of-way grant, agrees to comply 
with the following requirements:
    (a) The right-of-way holder shall comply with applicable laws and 
regulations and the terms of the grant.
    (b) The granting of the right-of-way shall be subject to the 
express condition that the rights granted shall not prevent or 
interfere in any way with the management, administration, or the 
granting of other rights by the United States, either prior or 
subsequent to the granting of the right-of-way. Moreover, the holder 
agrees to allow the occupancy and use by the United States, its 
lessees, or other right-of-way holders, of any part of the right-of-way 
grant not actually occupied or necessarily incident to its use for any 
necessary operations involved in the management, administration, or the 
enjoyment of such other granted rights.
    (c) If the right-of-way holder discovers any archaeological 
resource while conducting operations within the right-of-way, the 
right-of-way holder shall immediately halt operations within the area 
of the discovery and report the discovery to the Regional Director. If 
investigations determine that the resource is significant, the Regional 
Director will inform the right-of-way holder how to protect it.
    (d) The Regional Supervisor shall be kept informed at all times of 
the right-of-way holder's address and, if a corporation, the address of 
its principal place of business and the name and address of the officer 
or agent authorized to be served with process.
    (e) The right-of-way holder shall pay the United States or its 
lessees or right-of-way holders, as the case may be, the full value of 
all damages to the property of the United States or its said lessees or 
right-of-way holders and shall indemnify the United States against any 
and all liability for damages to life, person, or property arising from 
the occupation and use of the area covered by the right-of-way grant.
    (f)(1) The holder of a right-of-way oil or gas pipeline shall 
transport or purchase oil or natural gas produced from submerged lands 
in the vicinity of the pipeline without discrimination and in such 
proportionate amounts as the FERC may, after a full hearing with due 
notice thereof to the interested parties, determine to be reasonable, 
taking into account, among other things, conservation and the 
prevention of waste.
    (2) Unless otherwise exempted by FERC pursuant to 43 U.S.C. 
1334(f)(2), the holder shall:
    (i) Provide open and nondiscriminatory access to a right-of-way 
pipeline to both owner and nonowner shippers, and
    (ii) Comply with the provisions of 43 U.S.C. 1334(f)(1)(B) under 
which FERC may order an expansion of the throughput capacity of a 
right-of-way pipeline which is approved after September 18, 1978, and 
which is not located in the Gulf of Mexico or the Santa Barbara 
Channel.
    (g) The area covered by a right-of-way and all improvements thereon 
shall be kept open at all reasonable times for inspection by the Bureau 
of Safety and Environmental Enforcement (BSEE).

[[Page 64559]]

The right-of-way holder shall make available all records relative to 
the design, construction, operation, maintenance and repair, and 
investigations on or with regard to such area.
    (h) Upon relinquishment, forfeiture, or cancellation of a right-of-
way grant, the right-of-way holder shall remove all platforms, 
structures, domes over valves, pipes, taps, and valves along the right-
of-way. All of these improvements shall be removed by the holder within 
1 year of the effective date of the relinquishment, forfeiture, or 
cancellation unless this requirement is waived in writing by the 
Regional Supervisor. All such improvements not removed within the time 
provided herein shall become the property of the United States but that 
shall not relieve the holder of liability for the cost of their removal 
or for restoration of the site. Furthermore, the holder is responsible 
for accidents or damages which might occur as a result of failure to 
timely remove improvements and equipment and restore a site. An 
application for relinquishment of a right-of-way grant shall be filed 
in accordance with Sec.  250.1019 of this part.


Sec.  250.1011  [Reserved]


Sec.  250.1012  Required payments for pipeline right-of-way holders.

    (a) You must pay ONRR, under the regulations at 30 CFR part 1218, 
an annual rental of $15 for each statute mile, or part of a statute 
mile, of the OCS that your pipeline right-of-way crosses.
    (b) This paragraph applies to you if you obtain a pipeline right-
of-way that includes a site for an accessory to the pipeline, including 
but not limited to a platform. This paragraph also applies if you apply 
to modify a right-of-way to change the site footprint. In either case, 
you must pay the amounts shown in the following table.

----------------------------------------------------------------------------------------------------------------
                      If . . .                                                Then . . .
----------------------------------------------------------------------------------------------------------------
(1) Your accessory site is located in water depths    You must pay ONRR, under the regulations at 30 CFR part
 of less than 200 meters;                              1218, a rental of $5 per acre per year with a minimum of
                                                       $450 per year. The area subject to annual rental includes
                                                       the areal extent of anchor chains, pipeline risers, and
                                                       other facilities and devices associated with the
                                                       accessory.
(2) Your accessory site is located in water depths    You must pay ONRR, under the regulations at 30 CFR part
 of 200 meters or greater;                             1218, a rental of $7.50 per acre per year with a minimum
                                                       of $675 per year. The area subject to annual rental
                                                       includes the areal extent of anchor chains, pipeline
                                                       risers, and other facilities and devices associated with
                                                       the accessory.
----------------------------------------------------------------------------------------------------------------

     (c) If you hold a pipeline right-of-way that includes a site for 
an accessory to your pipeline and you are not covered by paragraph (b) 
of this section, then you must pay ONRR, under the regulations at 30 
CFR part 1218, an annual rental of $75 for use of the affected area.
    (d) You may make the rental payments required by paragraphs (a), 
(b)(1), (b)(2), and (c) of this section on an annual basis, for a 5-
year period, or for multiples of 5 years. You must make the first 
payment at the time you submit the pipeline right-of-way application. 
You must make all subsequent payments before the respective time 
periods begin.
    (e) Late payments. An interest charge will be assessed on unpaid 
and underpaid amounts from the date the amounts are due, in accordance 
with the provisions found in 30 CFR 1218.54. If you fail to make a 
payment that is late after written notice from ONRR, BSEE may initiate 
cancellation of the right-of-use grant and easement under Sec.  
250.1013.


Sec.  250.1013  Grounds for forfeiture of pipeline right-of-way grants.

    Failure to comply with the Act, regulations, or any conditions of 
the right-of-way grant prescribed by the Regional Supervisor shall be 
grounds for forfeiture of the grant in an appropriate judicial 
proceeding instituted by the United States in any U.S. District Court 
having jurisdiction in accordance with the provisions of 43 U.S.C. 
1349.


Sec.  250.1014  When pipeline right-of-way grants expire.

    Any right-of-way granted under the provisions of this subpart 
remains in effect as long as the associated pipeline is properly 
maintained and used for the purpose for which the grant was made, 
unless otherwise expressly stated in the grant. Temporary cessation or 
suspension of pipeline operations shall not cause the grant to expire. 
However, if the purpose of the grant ceases to exist or use of the 
associated pipeline is permanently discontinued for any reason, the 
grant shall be deemed to have expired.


Sec.  250.1015  Applications for pipeline right-of-way grants.

    (a) You must submit an original and three copies of an application 
for a new or modified pipeline ROW grant to the Regional Supervisor. 
The application must address those items required by Sec.  250.1007(a) 
or (b) of this subpart, as applicable. It must also state the primary 
purpose for which you will use the ROW grant. If the ROW has been used 
before the application is made, the application must state the date 
such use began, by whom, and the date the applicant obtained control of 
the improvement. When you file your application, you must pay the 
rental required under Sec.  250.1012 of this subpart, as well as the 
service fees listed in Sec.  250.125 of this part for a pipeline ROW 
grant to install a new pipeline, or to convert an existing lease term 
pipeline into a ROW pipeline. An application to modify an approved ROW 
grant must be accompanied by the additional rental required under Sec.  
250.1012 if applicable. You must file a separate application for each 
ROW.
    (b)(1) An individual applicant shall submit a statement of 
citizenship or nationality with the application. An applicant who is an 
alien lawfully admitted for permanent residence in the United States 
shall also submit evidence of such status with the application.
    (2) If the applicant is an association (including a partnership), 
the application shall also be accompanied by a certified copy of the 
articles of association or appropriate reference to a copy of such 
articles already filed with BSEE and a statement as to any subsequent 
amendments.
    (3) If the applicant is a corporation, the application shall also 
include the following:
    (i) A statement certified by the Secretary or Assistant Secretary 
of the corporation with the corporate seal showing the State in which 
it is incorporated and the name of the person(s) authorized to act on 
behalf of the corporation, or
    (ii) In lieu of such a statement, an appropriate reference to 
statements or records previously submitted to BSEE

[[Page 64560]]

(including material submitted in compliance with prior regulations).
    (c) The application shall include a list of every lessee and right-
of-way holder whose lease or right-of-way is intersected by the 
proposed right-of-way. The application shall also include a statement 
that a copy of the application has been sent by registered or certified 
mail to each such lessee or right-of-way holder.
    (d) The applicant shall include in the application an original and 
three copies of a completed Nondiscrimination in Employment form (YN 
3341-1 dated July 1982). These forms are available at each BSEE 
regional office.
    (e) Notwithstanding the provisions of paragraph (a) of this 
section, the requirements to pay filing fees under that paragraph are 
suspended until January 3, 2006.


Sec.  250.1016  Granting pipeline rights-of-way.

    (a) In considering an application for a right-of-way, the Regional 
Supervisor shall consider the potential effect of the associated 
pipeline on the human, marine, and coastal environments, life 
(including aquatic life), property, and mineral resources in the entire 
area during construction and operational phases. The Regional 
Supervisor shall prepare an environmental analysis in accordance with 
applicable policies and guidelines. To aid in the evaluation and 
determinations, the Regional Supervisor may request and consider views 
and recommendations of appropriate Federal Agencies, hold public 
meetings after appropriate notice, and consult, as appropriate, with 
State agencies, organizations, industries, and individuals. Before 
granting a pipeline right-of-way, the Regional Supervisor shall give 
consideration to any recommendation by the intergovernmental planning 
program, or similar process, for the assessment and management of OCS 
oil and gas transportation.
    (b) Should the proposed route of a right-of-way adjoin and 
subsequently cross any State submerged lands, the applicant shall 
submit evidence to the Regional Supervisor that the State(s) so 
affected has reviewed the application. The applicant shall also submit 
any comment received as a result of that review. In the event of a 
State recommendation to relocate the proposed route, the Regional 
Supervisor may consult with the appropriate State officials.
    (c)(1) The applicant shall submit photocopies of return receipts to 
the Regional Supervisor that indicate the date that each lessee or 
right-of-way holder referenced in Sec.  250.1015(c) of this part has 
received a copy of the application. Letters of no objection may be 
submitted in lieu of the return receipts.
    (2) The Regional Supervisor shall not take final action on a right-
of-way application until the Regional Supervisor is satisfied that each 
such lessee or right-of-way holder has been afforded at least 30 days 
from the date determined in paragraph (c)(1) of this section in which 
to submit comments.
    (d) If a proposed right-of-way crosses any lands not subject to 
disposition by mineral leasing or restricted from oil and gas 
activities, it shall be rejected by the Regional Supervisor unless the 
Federal Agency with jurisdiction over such excluded or restricted area 
gives its consent to the granting of the right-of-way. In such case, 
the applicant, upon a request filed within 30 days after receipt of the 
notification of such rejection, shall be allowed an opportunity to 
eliminate the conflict.
    (e)(1) If the application and other required information are found 
to be in compliance with applicable laws and regulations, the right-of-
way may be granted. The Regional Supervisor may prescribe, as 
conditions to the right-of-way grant, stipulations necessary to protect 
human, marine, and coastal environments, life (including aquatic life), 
property, and mineral resources located on or adjacent to the right-of-
way.
    (2) If the Regional Supervisor determines that a change in the 
application should be made, the Regional Supervisor shall notify the 
applicant that an amended application shall be filed subject to 
stipulated changes. The Regional Supervisor shall determine whether the 
applicant shall deliver copies of the amended application to other 
parties for comment.
    (3) A decision to reject an application shall be in writing and 
shall state the reasons for the rejection.


Sec.  250.1017  Requirements for construction under pipeline right-of-
way grants.

    (a) Failure to construct the associated right-of-way pipeline 
within 5 years of the date of the granting of a right-of-way shall 
cause the grant to expire.
    (b)(1) A right-of-way holder shall ensure that the right-of-way 
pipeline is constructed in a manner that minimizes deviations from the 
right-of-way as granted.
    (2) If, after constructing the right-of-way pipeline, it is 
determined that a deviation from the proposed right-of-way as granted 
has occurred, the right-of-way holder shall--
    (i) Notify the operators of all leases and holders of all right-of-
way grants in which a deviation has occurred, and within 60 days of the 
date of the acceptance by the Regional Supervisor of the completion of 
pipeline construction report, provide the Regional Supervisor with 
evidence of such notification; and
    (ii) Relinquish any unused portion of the right-of-way.
    (3) Substantial deviation of a right-of-way pipeline as constructed 
from the proposed right-of-way as granted may be grounds for forfeiture 
of the right-of-way.
    (c) If the Regional Supervisor determines that a significant change 
in conditions has occurred subsequent to the granting of a right-of-way 
but prior to the commencement of construction of the associated 
pipeline, the Regional Supervisor may suspend or temporarily prohibit 
the commencement of construction until the right-of-way grant is 
modified to the extent necessary to address the changed conditions.


Sec.  250.1018  Assignment of pipeline right-of-way grants.

    (a) Assignment may be made of a right-of-way grant, in whole or of 
any lineal segment thereof, subject to the approval of the Regional 
Supervisor. An application for approval of an assignment of a right-of-
way or of a lineal segment thereof, shall be filed in triplicate with 
the Regional Supervisor.
    (b) Any application for approval for an assignment, in whole or in 
part, of any right, title, or interest in a right-of-way grant must be 
accompanied by the same showing of qualifications of the assignees as 
is required of an applicant for a ROW in Sec.  250.1015 of this subpart 
and must be supported by a statement that the assignee agrees to comply 
with and to be bound by the terms and conditions of the ROW grant. The 
assignee must satisfy the bonding requirements in 30 CFR 550.1011. No 
transfer will be recognized unless and until it is first approved, in 
writing, by the Regional Supervisor. The assignee must pay the service 
fee listed in Sec.  250.125 of this part for a pipeline ROW assignment 
request.
    (c) Notwithstanding the provisions of paragraph (b) of this 
section, the requirement to pay a filing fee under that paragraph is 
suspended until January 3, 2006.


Sec.  250.1019  Relinquishment of pipeline right-of-way grants.

    A right-of-way grant or a portion thereof may be surrendered by the 
holder by filing a written relinquishment in triplicate with the

[[Page 64561]]

Regional Supervisor. It must contain those items addressed in 
Sec. Sec.  250.1751 and 250.1752 of this part. A relinquishment shall 
take effect on the date it is filed subject to the satisfaction of all 
outstanding debts, fees, or fines and the requirements in Sec.  
250.1010(h) of this part.

Subpart K--Oil and Gas Production Requirements

General


Sec.  250.1150  What are the general reservoir production requirements?

    You must produce wells and reservoirs at rates that provide for 
economic development while maximizing ultimate recovery and without 
adversely affecting correlative rights.

Well Tests and Surveys


Sec.  250.1151  How often must I conduct well production tests?

    (a) You must conduct well production tests as shown in the 
following table:

------------------------------------------------------------------------
                                             And you must submit to the
             You must conduct:                  Regional Supervisor:
------------------------------------------------------------------------
(1) A well-flow potential test on all new,  Form BSEE-0126, Well
 recompleted, or reworked well completions   Potential Test Report,
 within 30 days of the date of first         along with the supporting
 continuous production,                      data as listed in the table
                                             in Sec.   250.1167, within
                                             15 days after the end of
                                             the test period.
(2) At least one well test during a         Results on Form BSEE-0128,
 calendar half-year for each producing       Semiannual Well Test
 completion,                                 Report, of the most recent
                                             well test obtained. This
                                             must be submitted within 45
                                             days after the end of the
                                             calendar half-year.
------------------------------------------------------------------------

     (b) You may request an extension from the Regional Supervisor if 
you cannot submit the results of a semiannual well test within the 
specified time.
    (c) You must submit to the Regional Supervisor an original and two 
copies of the appropriate form required by paragraph (a) of this 
section; one of the copies of the form must be a public information 
copy in accordance with Sec. Sec.  250.186 and 250.197, and marked 
``Public Information.'' You must submit two copies of the supporting 
information as listed in the table in Sec.  250.1167 with form BSEE-
0126.


Sec.  250.1152  How do I conduct well tests?

    (a) When you conduct well tests you must:
    (1) Recover fluid from the well completion equivalent to the amount 
of fluid introduced into the formation during completion, recompletion, 
reworking, or treatment operations before you start a well test;
    (2) Produce the well completion under stabilized rate conditions 
for at least 6 consecutive hours before beginning the test period;
    (3) Conduct the test for at least 4 consecutive hours;
    (4) Adjust measured gas volumes to the standard conditions of 14.73 
pounds per square inch absolute (psia) and 60 [deg]F for all tests; and
    (5) Use measured specific gravity values to calculate gas volumes.
    (b) You may request approval from the Regional Supervisor to 
conduct a well test using alternative procedures if you can demonstrate 
test reliability under those procedures.
    (c) The Regional Supervisor may also require you to conduct the 
following tests and complete them within a specified time period:
    (1) A retest or a prolonged test of a well completion if it is 
determined to be necessary for the proper establishment of a Maximum 
Production Rate (MPR) or a Maximum Efficient Rate (MER); and
    (2) A multipoint back-pressure test to determine the theoretical 
open-flow potential of a gas well.
    (d) A BSEE representative may witness any well test. Upon request, 
you must provide advance notice to the Regional Supervisor of the times 
and dates of well tests.


Sec. Sec.  250.1153--250.1155  [Reserved]

Approvals Prior to Production


Sec.  250.1156  What steps must I take to receive approval to produce 
within 500 feet of a unit or lease line?

    (a) You must obtain approval from the Regional Supervisor before 
you start producing from a reservoir within a well that has any portion 
of the completed interval less than 500 feet from a unit or lease line. 
Submit to BSEE the service fee listed in Sec.  250.125, according to 
the instructions in Sec.  250.126, and the supporting information, as 
listed in the table in Sec.  250.1167, with your request. The Regional 
Supervisor will determine whether approval of your request will 
maximize ultimate recovery, avoid the waste of natural resources, or 
protect correlative rights. You do not need to obtain approval if the 
adjacent leases or units have the same unit, lease (record title and 
operating rights), and royalty interests as the lease or unit you plan 
to produce. You do not need to obtain approval if the adjacent block is 
unleased.
    (b) You must notify the operator(s) of adjacent property(ies) that 
are within 500 feet of the completion, if the adjacent acreage is a 
leased block in the Federal OCS. You must provide the Regional 
Supervisor proof of the date of the notification. The operators of the 
adjacent properties have 30 days after receiving the notification to 
provide the Regional Supervisor letters of acceptance or objection. If 
an adjacent operator does not respond within 30 days, the Regional 
Supervisor will presume there are no objections and proceed with a 
decision. The notification must include:
    (1) The well name;
    (2) The rectangular coordinates (x, y) of the location of the top 
and bottom of the completion or target completion referenced to the 
North American Datum 1983, and the subsea depths of the top and bottom 
of the completion or target completion;
    (3) The distance from the completion or target completion to the 
unit or lease line at its nearest point; and
    (4) A statement indicating whether or not it will be a high-
capacity completion having a perforated or open hole interval greater 
than 150 feet measured depth.


Sec.  250.1157  How do I receive approval to produce gas-cap gas from 
an oil reservoir with an associated gas cap?

    (a) You must request and receive approval from the Regional 
Supervisor:
    (1) Before producing gas-cap gas from each completion in an oil 
reservoir that is known to have an associated gas cap.
    (2) To continue production from a well if the oil reservoir is not 
initially known to have an associated gas cap, but the oil well begins 
to show characteristics of a gas well.
    (b) For either request, you must submit the service fee listed in 
Sec.  250.125, according to the instructions in Sec.  250.126, and the 
supporting information, as listed in the table in Sec.  250.1167, with 
your request.
    (c) The Regional Supervisor will determine whether your request 
maximizes ultimate recovery.

[[Page 64562]]

Sec.  250.1158  How do I receive approval to downhole commingle 
hydrocarbons?

    (a) Before you perforate a well, you must request and receive 
approval from the Regional Supervisor to commingle hydrocarbons 
produced from multiple reservoirs within a common wellbore. The 
Regional Supervisor will determine whether your request maximizes 
ultimate recovery. You must include the service fee listed in Sec.  
250.125, according to the instructions in Sec.  250.126, and the 
supporting information, as listed in the table in Sec.  250.1167, with 
your request.
    (b) If one or more of the reservoirs proposed for commingling is a 
competitive reservoir, you must notify the operators of all leases that 
contain the reservoir that you intend to downhole commingle the 
reservoirs. Your request for approval of downhole commingling must 
include proof of the date of this notification. The notified operators 
have 30 days after notification to provide the Regional Supervisor with 
letters of acceptance or objection. If the notified operators do not 
respond within the specified period, the Regional Supervisor will 
assume the operators do not object and proceed with a decision.

Production Rates


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

    (a) The Regional Supervisor may set a Maximum Production Rate (MPR) 
for a producing well completion, or set a Maximum Efficient Rate (MER) 
for a reservoir, or both, if the Regional Supervisor determines that an 
excessive production rate could harm ultimate recovery. An MPR or MER 
will be based on well tests and any limitations imposed by well and 
surface equipment, sand production, reservoir sensitivity, gas-oil and 
water-oil ratios, location of perforated intervals, and prudent 
operating practices.
    (b) If the Regional Supervisor sets an MPR for a producing well 
completion and/or an MER for a reservoir, you may not exceed those 
rates except due to normal variations and fluctuations in production 
rates as set by the Regional Supervisor.

Flaring, Venting, and Burning Hydrocarbons


Sec.  250.1160  When may I flare or vent gas?

    (a) You must request and receive approval from the Regional 
Supervisor to flare or vent natural gas at your facility, except in the 
following situations:

------------------------------------------------------------------------
               Condition                     Additional requirements
------------------------------------------------------------------------
(1) When the gas is lease use gas        The volume of gas flared or
 (produced natural gas which is used on   vented may not exceed the
 or for the benefit of lease operations   amount necessary for its
 such as gas used to operate production   intended purpose. Burning
 facilities) or is used as an additive    waste products may require
 necessary to burn waste products, such   approval under other
 as H2S.                                  regulations.
(2) During the restart of a facility     Flaring or venting may not
 that was shut in because of weather      exceed 48 cumulative hours
 conditions, such as a hurricane.         without Regional Supervisor
                                          approval.
(3) During the blow down of              (i) You must report the
 transportation pipelines downstream of   location, time, flare/vent
 the royalty meter.                       volume, and reason for flaring/
                                          venting to the Regional
                                          Supervisor in writing within
                                          72 hours after the incident is
                                          over.
                                         (ii) Additional approval may be
                                          required under subparts H and
                                          J of this part.
(4) During the unloading or cleaning of  You may not exceed 48
 a well, drill-stem testing, production   cumulative hours of flaring or
 testing, other well-evaluation           venting per unloading or
 testing, or the necessary blow down to   cleaning or testing operation
 perform these procedures.                on a single completion without
                                          Regional Supervisor approval.
(5) When properly working equipment      You may not flare or vent more
 yields flash gas (natural gas released   than an average of 50 MCF per
 from liquid hydrocarbons as a result     day during any calendar month
 of a decrease in pressure, an increase   without Regional Supervisor
 in temperature, or both) from storage    approval.
 vessels or other low-pressure
 production vessels, and you cannot
 economically recover this flash gas.
(6) When the equipment works properly    (i) For oil-well gas and gas-
 but there is a temporary upset           well flash gas (natural gas
 condition, such as a hydrate or          released from condensate as a
 paraffin plug.                           result of a decrease in
                                          pressure, an increase in
                                          temperature, or both), you may
                                          not exceed 48 continuous hours
                                          of flaring or venting without
                                          Regional Supervisor approval.
                                         (ii) For primary gas-well gas
                                          (natural gas from a gas well
                                          completion that is at or near
                                          its wellhead pressure; this
                                          does not include flash gas),
                                          you may not exceed 2
                                          continuous hours of flaring or
                                          venting without Regional
                                          Supervisor approval.
                                         (iii) You may not exceed 144
                                          cumulative hours of flaring or
                                          venting during a calendar
                                          month without Regional
                                          Supervisor approval.
(7) When equipment fails to work         (i) For oil-well gas and gas-
 properly, during equipment maintenance   well flash gas, you may not
 and repair, or when you must relieve     exceed 48 continuous hours of
 system pressures.                        flaring or venting without
                                          Regional Supervisor approval.
                                         (ii) For primary gas-well gas,
                                          you may not exceed 2
                                          continuous hours of flaring or
                                          venting without Regional
                                          Supervisor approval.
                                         (iii) You may not exceed 144
                                          cumulative hours of flaring or
                                          venting during a calendar
                                          month without Regional
                                          Supervisor approval.
                                         (iv) The continuous and
                                          cumulative hours allowed under
                                          this para