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[Federal Register Volume 76, Number 201 (Tuesday, October 18, 2011)]
[Rules and Regulations]
[Pages 64432-64780]
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.

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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.) 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 paragraph may be counted
                                          separately from the hours
                                          under paragraph (a)(6) of this
                                          section.
------------------------------------------------------------------------

     (b) Regardless of the requirements in paragraph (a) of this 
section, you must not flare or vent gas over the volume approved in 
your Development Operations Coordination Document (DOCD) or your 
Development and Production Plan (DPP) submitted to BOEM.
    (c) The Regional Supervisor may establish alternative approval 
procedures to cover situations when you cannot contact the BSEE office, 
such as during non-office hours.
    (d) The Regional Supervisor may specify a volume limit, or a 
shorter time limit than specified elsewhere in this

[[Page 64563]]

part, in order to prevent air quality degradation or loss of reserves.
    (e) If you flare or vent gas without the required approval, or if 
the Regional Supervisor determines that you were negligent or could 
have avoided flaring or venting the gas, the hydrocarbons will be 
considered avoidably lost or wasted. You must pay royalties on the loss 
or waste, according to 30 CFR part 1202. You must value any gas or 
liquid hydrocarbons avoidably lost or wasted under the provisions of 30 
CFR part 1206.
    (f) Fugitive emissions from valves, fittings, flanges, pressure 
relief valves or similar components do not require approval under this 
subpart unless specifically required by the Regional Supervisor.

Sec.  250.1161  When may I flare or vent gas for extended periods of 
time?

    You must request and receive approval from the Regional Supervisor 
to flare or vent gas for an extended period of time. The Regional 
Supervisor will specify the approved period of time, which will not 
exceed 1 year. The Regional Supervisor may deny your request if it does 
not ensure the conservation of natural resources or is not consistent 
with National interests relating to development and production of 
minerals of the OCS. The Regional Supervisor may approve your request 
for one of the following reasons:
    (a) You initiated an action which, when completed, will eliminate 
flaring and venting; or
    (b) You submit to the Regional Supervisor an evaluation supported 
by engineering, geologic, and economic data indicating that the oil and 
gas produced from the well(s) will not economically support the 
facilities necessary to sell the gas or to use the gas on or for the 
benefit of the lease.

Sec.  250.1162  When may I burn produced liquid hydrocarbons?

    (a) You must request and receive approval from the Regional 
Supervisor to burn any produced liquid hydrocarbons. The Regional 
Supervisor may allow you to burn liquid hydrocarbons if you demonstrate 
that transporting them to market or re-injecting them is not 
technically feasible or poses a significant risk of harm to offshore 
personnel or the environment.
    (b) If you burn liquid hydrocarbons without the required approval, 
or if the Regional Supervisor determines that you were negligent or 
could have avoided burning liquid hydrocarbons, the hydrocarbons will 
be considered avoidably lost or wasted. You must pay royalties on the 
loss or waste, according to 30 CFR part 1202. You must value any liquid 
hydrocarbons avoidably lost or wasted under the provisions of 30 CFR 
part 1206.

Sec.  250.1163  How must I measure gas flaring or venting volumes and 
liquid hydrocarbon burning volumes, and what records must I maintain?

    (a) If your facility processes more than an average of 2,000 bopd 
during May 2010, you must install flare/vent meters within 180 days 
after May 2010. If your facility processes more than an average of 
2,000 bopd during a calendar month after May 2010, you must install 
flare/vent meters within 120 days after the end of the month in which 
the average amount of oil processed exceeds 2,000 bopd.
    (1) You must notify the Regional Supervisor when your facility 
begins to process more than an average of 2,000 bopd in a calendar 
month;
    (2) The flare/vent meters must measure all flared and vented gas 
within 5 percent accuracy;
    (3) You must calibrate the meters regularly, in accordance with the 
manufacturer's recommendation, or at least once every year, whichever 
is shorter; and
    (4) You must use and maintain the flare/vent meters for the life of 
the facility.
    (b) You must report all hydrocarbons produced from a well 
completion, including all gas flared, gas vented, and liquid 
hydrocarbons burned, to Office of Natural Resources Revenue on Form 
ONRR-4054 (Oil and Gas Operations Report), in accordance with 30 CFR 
1210.102.
    (1) You must report the amount of gas flared and the amount of gas 
vented separately.
    (2) You may classify and report gas used to operate equipment on 
the lease, such as gas used to power engines, instrument gas, and gas 
used to maintain pilot lights, as lease use gas.
    (3) If flare/vent meters are required at one or more of your 
facilities, you must report the amount of gas flared and vented at each 
of those facilities separately from those facilities that do not 
require meters and separately from other facilities with meters.
    (4) If flare/vent meters are not required at your facility:
    (i) You may report the gas flared and vented on a lease or unit 
basis. Gas flared and vented from multiple facilities on a single lease 
or unit may be reported together.
    (ii) If you choose to install meters, you may report the gas volume 
flared and vented according to the method specified in paragraph (b)(3) 
of this section.
    (c) You must prepare and maintain records detailing gas flaring, 
gas venting, and liquid hydrocarbon burning for each facility for 6 
years.
    (1) You must maintain these records on the facility for at least 
the first 2 years and have them available for inspection by BSEE 
representatives.
    (2) After 2 years, you must maintain the records, allow BSEE 
representatives to inspect the records upon request and provide copies 
to the Regional Supervisor upon request, but are not required to keep 
them on the facility.
    (3) The records must include, at a minimum:
    (i) Daily volumes of gas flared, gas vented, and liquid 
hydrocarbons burned;
    (ii) Number of hours of gas flaring, gas venting, and liquid 
hydrocarbon burning, on a daily and monthly cumulative basis;
    (iii) A list of the wells contributing to gas flaring, gas venting, 
and liquid hydrocarbon burning, along with gas-oil ratio data;
    (iv) Reasons for gas flaring, gas venting, and liquid hydrocarbon 
burning; and
    (v) Documentation of all required approvals.
    (d) If your facility is required to have flare/vent meters:
    (1) You must maintain the meter recordings for 6 years.
    (i) You must keep these recordings on the facility for 2 years and 
have them available for inspection by BSEE representatives.
    (ii) After 2 years, you must maintain the recordings, allow BSEE 
representatives to inspect the recordings upon request and provide 
copies to the Regional Supervisor upon request, but are not required to 
keep them on the facility.
    (iii) These recordings must include the begin times, end times, and 
volumes for all flaring and venting incidents.
    (2) You must maintain flare/vent meter calibration and maintenance 
records on the facility for 2 years.
    (e) If your flaring or venting of gas, or burning of liquid 
hydrocarbons, required written or oral approval, you must submit 
documentation to the Regional Supervisor summarizing the location, 
dates, number of hours, and volumes of gas flared, gas vented, and 
liquid hydrocarbons burned under the approval.

Sec.  250.1164  What are the requirements for flaring or venting gas 
containing H2S?

    (a) You may not vent gas containing H2S, except for 
minor releases during maintenance and repair activities that do not 
result in a 15-minute time-

[[Page 64564]]

weighted average atmosphere concentration of H2S of 20 ppm 
or higher anywhere on the platform.
    (b) You may flare gas containing H2S only if you meet 
the requirements of Sec. Sec.  250.1160, 250.1161, 250.1163, and the 
following additional requirements:
    (1) For safety or air pollution prevention purposes, the Regional 
Supervisor may further restrict the flaring of gas containing 
H2S. The Regional Supervisor will use information provided 
in the lessee's H2S Contingency Plan (Sec.  250.490(f)), 
Exploration Plan, DPP, DOCD submitted to BOEM, and associated documents 
to determine the need for restrictions; and
    (2) If the Regional Supervisor determines that flaring at a 
facility or group of facilities may significantly affect the air 
quality of an onshore area, the Regional Supervisor may require you to 
conduct an air quality modeling analysis, under 30 CFR 550.303, to 
determine the potential effect of facility emissions. The Regional 
Supervisor may require monitoring and reporting, or may restrict or 
prohibit flaring, under 30 CFR 550.303 and 30 CFR 550.304.
    (c) The Regional Supervisor may require you to submit monthly 
reports of flared and vented gas containing H2S. Each report 
must contain, on a daily basis:
    (1) The volume and duration of each flaring and venting occurrence;
    (2) H2S concentration in the flared or vented gas; and
    (3) The calculated amount of SO2 emitted.

Other Requirements

Sec.  250.1165  What must I do for enhanced recovery operations?

    (a) You must promptly initiate enhanced oil and gas recovery 
operations for all reservoirs where these operations would result in an 
increase in ultimate recovery of oil or gas under sound engineering and 
economic principles.
    (b) Before initiating enhanced recovery operations, you must submit 
a proposed plan to the BSEE Regional Supervisor and receive approval 
for pressure maintenance, secondary or tertiary recovery, cycling, and 
similar recovery operations intended to increase the ultimate recovery 
of oil and gas from a reservoir. The proposed plan must include, for 
each project reservoir, a geologic and engineering overview, Form BOEM-
0127, and supporting data as required in Sec.  250.1167, 30 CFR 
550.1167, and any additional information required by the BSEE Regional 
Supervisor.
    (c) You must report to Office of Natural Resources Revenue the 
volumes of oil, gas, or other substances injected, produced, or 
produced for a second time under 30 CFR 1210.102.

Sec.  250.1166  What additional reporting is required for developments 
in the Alaska OCS Region?

    (a) For any development in the Alaska OCS Region, you must submit 
an annual reservoir management report to the Regional Supervisor. The 
report must contain information detailing the activities performed 
during the previous year and planned for the upcoming year that will:
    (1) Provide for the prevention of waste;
    (2) Provide for the protection of correlative rights; and
    (3) Maximize ultimate recovery of oil and gas.
    (b) If your development is jointly regulated by BSEE and the State 
of Alaska, BSEE and the Alaska Oil and Gas Conservation Commission will 
jointly determine appropriate reporting requirements to minimize or 
eliminate duplicate reporting requirements.
    (c) [Reserved]

Sec.  250.1167  What information must I submit with forms and for 
approvals?

    You must submit the supporting information listed in the following 
table with the form identified in column 1 and for the approvals 
required under this subpart identified in columns 2 through 4:

----------------------------------------------------------------------------------------------------------------
                                                                                                    Production
                                               WPT BSEE-0126       Gas cap          Downhole      within 500-ft
                                                 (2 copies)       production      commingling      of a unit or
                                                                                                    lease line
----------------------------------------------------------------------------------------------------------------
(a) Maps:
    (1) Base map with surface, bottomhole,    ...............        [bcheck]         [bcheck]         [bcheck]
     and completion locations with respect
     to the unit or lease line and the
     orientation of representative seismic
     lines or cross-sections................
    (2) Structure maps with penetration             [bcheck]         [bcheck]         [bcheck]         [bcheck]
     point and subsea depth for each well
     penetrating the reservoirs,
     highlighting subject wells; reservoir
     boundaries; and original and current
     fluid levels...........................
    (3) Net sand isopach with total net sand  ...............        [bcheck]         [bcheck]   ...............
     penetrated for each well, identified at
     the penetration point..................
    (4) Net hydrocarbon isopach with net      ...............        [bcheck]         [bcheck]   ...............
     feet of pay for each well, identified
     at the penetration point...............
(b) Seismic data:
    (1) Representative seismic lines,         ...............        [bcheck]         [bcheck]         [bcheck]
     including strike and dip lines that
     confirm the structure; indicate
     polarity...............................
    (2) Amplitude extraction of seismic       ...............        [bcheck]         [bcheck]         [bcheck]
     horizon, if applicable.................
(c) Logs:
    (1) Well log sections with tops and             [bcheck]         [bcheck]         [bcheck]         [bcheck]
     bottoms of the reservoir(s) and
     proposed or existing perforations......
    (2) Structural cross-sections showing     ...............        [bcheck]         [bcheck]                *
     the subject well and nearby wells......
(d) Engineering data:
    (1) Estimated recoverable reserves for    ...............        [dagger]         [dagger]         [bcheck]
     each well completion in the reservoir;
     total recoverable reserves for each
     reservoir; method of calculation;
     reservoir parameters used in volumetric
     and decline curve analysis.............
    (2) Well schematics showing current and   ...............        [bcheck]         [bcheck]         [bcheck]
     proposed conditions....................
    (3) The drive mechanism of each           ...............        [bcheck]         [bcheck]         [bcheck]
     reservoir..............................
    (4) Pressure data, by date, and whether   ...............        [bcheck]         [bcheck]   ...............
     they are estimated or measured.........
    (5) Production data and decline curve     ...............        [bcheck]         [bcheck]   ...............
     analysis indicative of the reservoir
     performance............................

[[Page 64565]]

 
    (6) Reservoir simulation with the         ...............               *                *                *
     reservoir parameters used, history
     matches, and prediction runs (include
     proposed development scenario).........
(e) General information:
    (1) Detailed economic analysis..........  ...............               *                *   ...............
    (2) Reservoir name and whether or not it  ...............        [bcheck]         [bcheck]         [bcheck]
     is competitive as defined under Sec.
     250.105................................
    (3) Operator name, lessee name(s),        ...............        [bcheck]         [bcheck]         [bcheck]
     block, lease number, royalty rate, and
     unit number (if applicable) of all
     relevant leases........................
    (4) Geologic overview of project........  ...............        [bcheck]         [bcheck]         [bcheck]
    (5) Explanation of why the proposed       ...............        [bcheck]         [bcheck]         [bcheck]
     completion scenario will maximize
     ultimate recovery......................
    (6) List of all wells in subject          ...............        [bcheck]         [bcheck]         [bcheck]
     reservoirs that have ever produced or
     been used for injection................
----------------------------------------------------------------------------------------------------------------
[bcheck] Required.
[dagger] Each Gas Cap Production request and Downhole Commingling request must include the estimated recoverable
  reserves for (1) the case where your proposed production scenario is approved, and (2) the case where your
  proposed production scenario is denied.
* Additional items the Regional Supervisor may request.
Note: All maps must be at a standard scale and show lease and unit lines. The Regional Supervisor may waive
  submittal of some of the required data on a case-by-case basis.

    (f) Depending on the type of approval requested, you must submit 
the appropriate payment of the service fee(s) listed in Sec.  250.125, 
according to the instructions in Sec.  250.126.

Subpart L--Oil and Gas Production Measurement, Surface Commingling, 
and Security

Sec.  250.1200  Question index table.

    The table in this section lists questions concerning Oil and Gas 
Production Measurement, Surface Commingling, and Security.

------------------------------------------------------------------------
            Frequently asked questions                  CFR citation
------------------------------------------------------------------------
1. What are the requirements for measuring liquid   Sec.   250.1202(a)
 hydrocarbons?
2. What are the requirements for liquid             Sec.   250.1202(b)
 hydrocarbon royalty meters?
3. What are the requirements for run tickets?       Sec.   250.1202(c)
4. What are the requirements for liquid             Sec.   250.1202(d)
 hydrocarbon royalty meter provings?
5. What are the requirements for calibrating a      Sec.   250.1202(e)
 master meter used in royalty meter provings?
6. What are the requirements for calibrating        Sec.   250.1202(f)
 mechanical-displacement provers and tank provers?
7. What correction factors must a lessee use when   Sec.   250.1202(g)
 proving meters with a mechanical displacement
 prover, tank prover, or master meter?
8. What are the requirements for establishing and   Sec.   250.1202(h)
 applying operating meter factors for liquid
 hydrocarbons?
9. Under what circumstances does a liquid           Sec.   250.1202(i)
 hydrocarbon royalty meter need to be taken out of
 service, and what must a lessee do?
10. How must a lessee correct gross liquid          Sec.   250.1202(j)
 hydrocarbon volumes to standard conditions?
11. What are the requirements for liquid            Sec.   250.1202(k)
 hydrocarbon allocation meters?
12. What are the requirements for royalty and       Sec.   250.1202(l)
 inventory tank facilities?
13. To which meters do BSEE requirements for gas    Sec.   250.1203(a)
 measurement apply?
14. What are the requirements for measuring gas?    Sec.   250.1203(b)
15. What are the requirements for gas meter         Sec.   250.1203(c)
 calibrations?
16. What must a lessee do if a gas meter is out of  Sec.   250.1203(d)
 calibration or malfunctioning?
17. What are the requirements when natural gas      Sec.   250.1203(e)
 from a Federal lease is transferred to a gas
 plant before royalty determination?
18. What are the requirements for measuring gas     Sec.   250.1203(f)
 lost or used on a lease?
19. What are the requirements for the surface       Sec.   250.1204(a)
 commingling of production?
20. What are the requirements for a periodic well   Sec.   250.1204(b)
 test used for allocation?
21. What are the requirements for site security?    Sec.   250.1205(a)
22. What are the requirements for using seals?      Sec.   250.1205(b)
------------------------------------------------------------------------

Sec.  250.1201  Definitions.

    Terms not defined in this section have the meanings given in the 
applicable chapter of the API MPMS, which is incorporated by reference 
in Sec.  250.198. Terms used in Subpart L have the following meaning:
    Allocation meter--a meter used to determine the portion of 
hydrocarbons attributable to one or more platforms, leases, units, or 
wells, in relation to the total production from a royalty or allocation 
measurement point.
    API MPMS--the American Petroleum Institute's Manual of Petroleum 
Measurement Standards, chapters 1, 20, and 21.
    British Thermal Unit (Btu)--the amount of heat needed to raise the 
temperature of one pound of water from 59.5 degrees Fahrenheit (59.5 
[deg]F) to 60.5 degrees Fahrenheit (60.5 [deg]F) at standard pressure 
base (14.73 pounds per square inch absolute (psia)).

[[Page 64566]]

    Compositional Analysis--separating mixtures into identifiable 
components expressed in mole percent.
    Force majeure event--an event beyond your control such as war, act 
of terrorism, crime, or act of nature which prevents you from operating 
the wells and meters on your OCS facility.
    Gas lost--gas that is neither sold nor used on the lease or unit 
nor used internally by the producer.
    Gas processing plant--an installation that uses any process 
designed to remove elements or compounds (hydrocarbon and non-
hydrocarbon) from gas, including absorption, adsorption, or 
refrigeration. Processing does not include treatment operations, 
including those necessary to put gas into marketable conditions such as 
natural pressure reduction, mechanical separation, heating, cooling, 
dehydration, desulphurization, and compression. The changing of 
pressures or temperatures in a reservoir is not processing.
    Gas processing plant statement--a monthly statement showing the 
volume and quality of the inlet or field gas stream and the plant 
products recovered during the period, volume of plant fuel, flare and 
shrinkage, and the allocation of these volumes to the sources of the 
inlet stream.
    Gas royalty meter malfunction--an error in any component of the gas 
measurement system which exceeds contractual tolerances.
    Gas volume statement--a monthly statement showing gas measurement 
data, including the volume (Mcf) and quality (Btu) of natural gas which 
flowed through a meter.
    Inventory tank--a tank in which liquid hydrocarbons are stored 
prior to royalty measurement. The measured volumes are used in the 
allocation process.
    Liquid hydrocarbons (free liquids)--hydrocarbons which exist in 
liquid form at standard conditions after passing through separating 
facilities.
    Malfunction factor--a liquid hydrocarbon royalty meter factor that 
differs from the previous meter factor by an amount greater than 
0.0025.
    Natural gas--a highly compressible, highly expandable mixture of 
hydrocarbons which occurs naturally in a gaseous form and passes a 
meter in vapor phase.
    Operating meter--a royalty or allocation meter that is used for gas 
or liquid hydrocarbon measurement for any period during a calibration 
cycle.
    Pipeline (retrograde) condensate--liquid hydrocarbons which drop 
out of the separated gas stream at any point in a pipeline during 
transmission to shore.
    Pressure base--the pressure at which gas volumes and quality are 
reported. The standard pressure base is 14.73 psia.
    Prove--to determine (as in meter proving) the relationship between 
the volume passing through a meter at one set of conditions and the 
indicated volume at those same conditions.
    Royalty meter--a meter approved for the purpose of determining the 
volume of gas, oil, or other components removed, saved, or sold from a 
Federal lease.
    Royalty tank--an approved tank in which liquid hydrocarbons are 
measured and upon which royalty volumes are based.
    Run ticket--the invoice for liquid hydrocarbons measured at a 
royalty point.
    Sales meter--a meter at which custody transfer takes place (not 
necessarily a royalty meter).
    Seal--a device or approved method used to prevent tampering with 
royalty measurement components.
    Standard conditions--atmospheric pressure of 14.73 pounds per 
square inch absolute (psia) and 60 [deg]F.
    Surface commingling--the surface mixing of production from two or 
more leases and/or unit participating areas prior to royalty 
measurement.
    Temperature base--the temperature at which gas and liquid 
hydrocarbon volumes and quality are reported. The standard temperature 
base is 60 [deg]F.
    Verification/Calibration--testing and correcting, if necessary, a 
measuring device to ensure compliance with industry accepted, 
manufacturer's recommended, or regulatory required standard of 
accuracy.
    You or your--the lessee or the operator or other lessees' 
representative engaged in operations in the Outer Continental Shelf 
(OCS).

Sec.  250.1202  Liquid hydrocarbon measurement.

    (a) What are the requirements for measuring liquid hydrocarbons? 
You must:
    (1) Submit a written application to, and obtain approval from, the 
Regional Supervisor before commencing liquid hydrocarbon production, or 
making any changes to the previously-approved measurement and/or 
allocation procedures. Your application (which may also include any 
relevant gas measurement and surface commingling requests) must be 
accompanied by payment of the service fee listed in Sec.  250.125. The 
service fees are divided into two levels based on complexity as shown 
in the following table.

------------------------------------------------------------------------
      Application type                          Actions
------------------------------------------------------------------------
(i) Simple applications,      Applications to temporarily reroute
                               production (for a duration not to exceed
                               six months); Production tests prior to
                               pipeline construction; Departures related
                               to meter proving, well testing, or
                               sampling frequency.
(ii) Complex applications,    Creation of new facility measurement
                               points (FMPs); Association of leases or
                               units with existing FMPs; Inclusion of
                               production from additional structures;
                               Meter updates which add buy-back gas
                               meters or pigging meters; Other
                               applications which request deviations
                               from the approved allocation procedures.
------------------------------------------------------------------------

     (2) Use measurement equipment that will accurately measure the 
liquid hydrocarbons produced from a lease or unit;
    (3) Use procedures and correction factors according to the 
applicable chapters of the API MPMS as incorporated by reference in 
Sec.  250.198, when obtaining net standard volume and associated 
measurement parameters; and
    (4) When requested by the Regional Supervisor, provide the pipeline 
(retrograde) condensate volumes as allocated to the individual leases 
or units.
    (b) What are the requirements for liquid hydrocarbon royalty 
meters? You must:
    (1) Ensure that the royalty meter facilities include the following 
approved components (or other BSEE-approved components) which must be 
compatible with their connected systems:
    (i) A meter equipped with a nonreset totalizer;
    (ii) A calibrated mechanical displacement (pipe) prover, master 
meter, or tank prover;
    (iii) A proportional-to-flow sampling device pulsed by the meter 
output;
    (iv) A temperature measurement or temperature compensation device; 
and
    (v) A sediment and water monitor with a probe located upstream of 
the divert valve.

[[Page 64567]]

    (2) Ensure that the royalty meter facilities accomplish the 
following:
    (i) Prevent flow reversal through the meter;
    (ii) Protect meters subjected to pressure pulsations or surges;
    (iii) Prevent the meter from being subjected to shock pressures 
greater than the maximum working pressure; and
    (iv) Prevent meter bypassing.
    (3) Maintain royalty meter facilities to ensure the following:
    (i) Meters operate within the gravity range specified by the 
manufacturer;
    (ii) Meters operate within the manufacturer's specifications for 
maximum and minimum flow rate for linear accuracy; and
    (iii) Meters are reproven when changes in metering conditions 
affect the meters' performance such as changes in pressure, 
temperature, density (water content), viscosity, pressure, and flow 
rate.
    (4) Ensure that sampling devices conform to the following:
    (i) The sampling point is in the flowstream immediately upstream or 
downstream of the meter or divert valve in accordance with the API MPMS 
(as incorporated by reference in Sec.  250.198);
    (ii) The sample container is vapor-tight and includes a power 
mixing device to allow complete mixing of the sample before removal 
from the container; and
    (iii) The sample probe is in the center half of the pipe diameter 
in a vertical run and is located at least three pipe diameters 
downstream of any pipe fitting within a region of turbulent flow. The 
sample probe can be located in a horizontal pipe if adequate stream 
conditioning such as power mixers or static mixers are installed 
upstream of the probe according to the manufacturer's instructions.
    (c) What are the requirements for run tickets? You must:
    (1) For royalty meters, ensure that the run tickets clearly 
identify all observed data, all correction factors not included in the 
meter factor, and the net standard volume.
    (2) For royalty tanks, ensure that the run tickets clearly identify 
all observed data, all applicable correction factors, on/off seal 
numbers, and the net standard volume.
    (3) Pull a run ticket at the beginning of the month and immediately 
after establishing the monthly meter factor or a malfunction meter 
factor.
    (4) Send all run tickets for royalty meters and tanks to the 
Regional Supervisor within 15 days after the end of the month;
    (d) What are the requirements for liquid hydrocarbon royalty meter 
provings? You must:
    (1) Permit BSEE representatives to witness provings;
    (2) Ensure that the integrity of the prover calibration is 
traceable to test measures certified by the National Institute of 
Standards and Technology;
    (3) Prove each operating royalty meter to determine the meter 
factor monthly, but the time between meter factor determinations must 
not exceed 42 days. When a force majeure event precludes the required 
monthly meter proving, meters must be proved within 15 days after being 
returned to service. The meters must be proved monthly thereafter, but 
the time between meter factor determinations must not exceed 42 days;
    (4) Obtain approval from the Regional Supervisor before proving on 
a schedule other than monthly; and
    (5) Submit copies of all meter proving reports for royalty meters 
to the Regional Supervisor monthly within 15 days after the end of the 
month.
    (e) What are the requirements for calibrating a master meter used 
in royalty meter provings? You must:
    (1) Calibrate the master meter to obtain a master meter factor 
before using it to determine operating meter factors;
    (2) Use a fluid of similar gravity, viscosity, temperature, and 
flow rate as the liquid hydrocarbons that flow through the operating 
meter to calibrate the master meter;
    (3) Calibrate the master meter monthly, but the time between 
calibrations must not exceed 42 days;
    (4) Calibrate the master meter by recording runs until the results 
of two consecutive runs (if a tank prover is used) or five out of six 
consecutive runs (if a mechanical-displacement prover is used) produce 
meter factor differences of no greater than 0.0002. Lessees must use 
the average of the two (or the five) runs that produced acceptable 
results to compute the master meter factor;
    (5) Install the master meter upstream of any back-pressure or 
reverse flow check valves associated with the operating meter. However, 
the master meter may be installed either upstream or downstream of the 
operating meter; and
    (6) Keep a copy of the master meter calibration report at your 
field location for 2 years.
    (f) What are the requirements for calibrating mechanical-
displacement provers and tank provers? You must:
    (1) Calibrate mechanical-displacement provers and tank provers at 
least once every 5 years according to the API MPMS (as incorporated by 
reference in Sec.  250.198); and
    (2) Submit a copy of each calibration report to the Regional 
Supervisor within 15 days after the calibration.
    (g) What correction factors must I use when proving meters with a 
mechanical-displacement prover, tank prover, or master meter? Calculate 
the following correction factors using the API MPMS:
    (1) The change in prover volume due to the effect of temperature on 
steel (Cts);
    (2) The change in prover volume due to the effect of pressure on 
steel (Cps);
    (3) The change in liquid volume due to the effect of temperature on 
a liquid (Ctl); and
    (4) The change in liquid volume due to the effect of pressure on a 
liquid (Cpl).
    (h) What are the requirements for establishing and applying 
operating meter factors for liquid hydrocarbons? (1) If you use a 
mechanical-displacement prover, you must record proof runs until five 
out of six consecutive runs produce a difference between individual 
runs of no greater than .05 percent. You must use the average of the 
five accepted runs to compute the meter factor.
    (2) If you use a master meter, you must record proof runs until 
three consecutive runs produce a total meter factor difference of no 
greater than 0.0005. The flow rate through the meters during the 
proving must be within 10 percent of the rate at which the line meter 
will operate. The final meter factor is determined by averaging the 
meter factors of the three runs;
    (3) If you use a tank prover, you must record proof runs until two 
consecutive runs produce a meter factor difference of no greater than 
.0005. The final meter factor is determined by averaging the meter 
factors of the two runs; and
    (4) You must apply operating meter factors forward starting with 
the date of the proving.
    (i) Under what circumstances does a liquid hydrocarbon royalty 
meter need to be taken out of service, and what must I do? (1) If the 
difference between the meter factor and the previous factor exceeds 
0.0025 it is a malfunction factor, and you must:
    (i) Remove the meter from service and inspect it for damage or 
wear;
    (ii) Adjust or repair the meter, and reprove it;
    (iii) Apply the average of the malfunction factor and the previous 
factor to the production measured through the meter between the date of 
the previous factor and the date of the malfunction factor; and

[[Page 64568]]

    (iv) Indicate that a meter malfunction occurred and show all 
appropriate remarks regarding subsequent repairs or adjustments on the 
proving report.
    (2) If a meter fails to register production, you must:
    (i) Remove the meter from service, repair and reprove it;
    (ii) Apply the previous meter factor to the production run between 
the date of that factor and the date of the failure; and
    (iii) Estimate and report unregistered production on the run 
ticket.
    (3) If the results of a royalty meter proving exceed the run 
tolerance criteria and all measures excluding the adjustment or repair 
of the meter cannot bring results within tolerance, you must:
    (i) Establish a factor using proving results made before any 
adjustment or repair of the meter; and
    (ii) Treat the established factor like a malfunction factor (see 
paragraph (i)(1) of this section).
    (j) How must I correct gross liquid hydrocarbon volumes to standard 
conditions? To correct gross liquid hydrocarbon volumes to standard 
conditions, you must:
    (1) Include Cpl factors in the meter factor calculation or list and 
apply them on the appropriate run ticket.
    (2) List Ctl factors on the appropriate run ticket when the meter 
is not automatically temperature compensated.
    (k) What are the requirements for liquid hydrocarbon allocation 
meters? For liquid hydrocarbon allocation meters you must:
    (1) Take samples continuously proportional to flow or daily (use 
the procedure in the applicable chapter of the API MPMS as incorporated 
by reference in Sec.  250.198;
    (2) For turbine meters, take the sample proportional to the flow 
only;
    (3) Prove operating allocation meters monthly if they measure 50 or 
more barrels per day per meter the previous month. When a force majeure 
event precludes the required monthly meter proving, meters must be 
proved within 15 days after being returned to service. The meters must 
be proved monthly thereafter; or
    (4) Prove operating allocation meters quarterly if they measure 
less than 50 barrels per day per meter the previous month. When a force 
majeure event precludes the required quarterly meter proving, meters 
must be proved within 15 days after being returned to service. The 
meters must be proved quarterly thereafter;
    (5) Keep a copy of the proving reports at the field location for 2 
years;
    (6) Adjust and reprove the meter if the meter factor differs from 
the previous meter factor by more than 2 percent and less than 7 
percent;
    (7) For turbine meters, remove from service, inspect and reprove 
the meter if the factor differs from the previous meter factor by more 
than 2 percent and less than 7 percent;
    (8) Repair and reprove, or replace and prove the meter if the meter 
factor differs from the previous meter factor by 7 percent or more; and
    (9) Permit BSEE representatives to witness provings.
    (l) What are the requirements for royalty and inventory tank 
facilities? You must:
    (1) Equip each royalty and inventory tank with a vapor-tight thief 
hatch, a vent-line valve, and a fill line designed to minimize free 
fall and splashing;
    (2) For royalty tanks, submit a complete set of calibration charts 
(tank tables) to the Regional Supervisor before using the tanks for 
royalty measurement;
    (3) For inventory tanks, retain the calibration charts for as long 
as the tanks are in use and submit them to the Regional Supervisor upon 
request; and
    (4) Obtain the volume and other measurement parameters by using 
correction factors and procedures in the API MPMS as incorporated by 
reference in Sec.  250.198.

Sec.  250.1203  Gas measurement.

    (a) To which meters do BSEE requirements for gas measurement apply? 
BSEE requirements for gas measurements apply to all OCS gas royalty and 
allocation meters.
    (b) What are the requirements for measuring gas? You must:
    (1) Submit a written application to, and obtain approval from, the 
Regional Supervisor before commencing gas production, or making any 
changes to the previously-approved measurement and/or allocation 
procedures. Your application (which may also include any relevant 
liquid hydrocarbon measurement and surface commingling requests) must 
be accompanied by payment of the service fee listed in Sec.  250.125. 
The service fees are divided into two levels based on complexity, see 
table in Sec.  250.1202(a)(1).
    (2) Design, install, use, maintain, and test measurement equipment 
to ensure accurate and verifiable measurement. You must follow the 
recommendations in API MPMS (as incorporated by reference in Sec.  
250.198).
    (3) Ensure that the measurement components demonstrate consistent 
levels of accuracy throughout the system.
    (4) Equip the meter with a chart or electronic data recorder. If an 
electronic data recorder is used, you must follow the recommendations 
in API MPMS.
    (5) Take proportional-to-flow or spot samples upstream or 
downstream of the meter at least once every 6 months.
    (6) When requested by the Regional Supervisor, provide available 
information on the gas quality.
    (7) Ensure that standard conditions for reporting gross heating 
value (Btu) are at a base temperature of 60 [deg]F and at a base 
pressure of 14.73 psia and reflect the same degree of water saturation 
as in the gas volume.
    (8) When requested by the Regional Supervisor, submit copies of gas 
volume statements for each requested gas meter. Show whether gas 
volumes and gross Btu heating values are reported at saturated or 
unsaturated conditions; and
    (9) When requested by the Regional Supervisor, provide volume and 
quality statements on dispositions other than those on the gas volume 
statement.
    (c) What are the requirements for gas meter calibrations? You must:
    (1) Verify/calibrate operating meters monthly, but do not exceed 42 
days between verifications/calibrations. When a force majeure event 
precludes the required monthly meter verification/calibration, meters 
must be verified/calibrated within 15 days after being returned to 
service. The meters must be verified/calibrated monthly thereafter, but 
do not exceed 42 days between meter verifications/calibrations;
    (2) Calibrate each meter by using the manufacturer's 
specifications;
    (3) Conduct calibrations as close as possible to the average hourly 
rate of flow since the last calibration;
    (4) Retain calibration reports at the field location for 2 years, 
and send the reports to the Regional Supervisor upon request; and
    (5) Permit BSEE representatives to witness calibrations.
    (d) What must I do if a gas meter is out of calibration or 
malfunctioning? If a gas meter is out of calibration or malfunctioning, 
you must:
    (1) If the readings are greater than the contractual tolerances, 
adjust the meter to function properly or remove it from service and 
replace it.
    (2) Correct the volumes to the last acceptable calibration as 
follows:
    (i) If the duration of the error can be determined, calculate the 
volume adjustment for that period.
    (ii) If the duration of the error cannot be determined, apply the 
volume adjustment to one-half of the time elapsed since the last 
calibration or 21 days, whichever is less.
    (e) What are the requirements when natural gas from a Federal lease 
on the OCS is transferred to a gas plant before

[[Page 64569]]

royalty determination? If natural gas from a Federal lease on the OCS 
is transferred to a gas plant before royalty determination:
    (1) You must provide the following to the Regional Supervisor upon 
request:
    (i) A copy of the monthly gas processing plant allocation 
statement; and
    (ii) Gross heating values of the inlet and residue streams when not 
reported on the gas plant statement.
    (2) You must permit BSEE to inspect the measurement and sampling 
equipment of natural gas processing plants that process Federal 
production.
    (f) What are the requirements for measuring gas lost or used on a 
lease? (1) You must either measure or estimate the volume of gas lost 
or used on a lease.
    (2) If you measure the volume, document the measurement equipment 
used and include the volume measured.
    (3) If you estimate the volume, document the estimating method, the 
data used, and the volumes estimated.
    (4) You must keep the documentation, including the volume data, 
easily obtainable for inspection at the field location for at least 2 
years, and must retain the documentation at a location of your choosing 
for at least 7 years after the documentation is generated, subject to 
all other document retention and production requirements in 30 U.S.C. 
1713 and 30 CFR part 1212.
    (5) Upon the request of the Regional Supervisor, you must provide 
copies of the records.

Sec.  250.1204  Surface commingling.

    (a) What are the requirements for the surface commingling of 
production? You must:
    (1) Submit a written application to, and obtain approval from, the 
Regional Supervisor before commencing the commingling of production or 
making any changes to the previously approved commingling procedures. 
Your application (which may also include any relevant liquid 
hydrocarbon and gas measurement requests) must be accompanied by 
payment of the service fee listed in Sec.  250.125. The service fees 
are divided into two levels based on complexity, see table in Sec.  
250.1202(a)(1).
    (2) Upon the request of the Regional Supervisor, lessees who 
deliver State lease production into a Federal commingling system must 
provide volumetric or fractional analysis data on the State lease 
production through the designated system operator.
    (b) What are the requirements for a periodic well test used for 
allocation? You must:
    (1) Conduct a well test at least once every 60 days unless the 
Regional Supervisor approves a different frequency. When a force 
majeure event precludes the required well test within the prescribed 60 
day period (or other frequency approved by the Regional Supervisor), 
wells must be tested within 15 days after being returned to production. 
Thereafter, well tests must be conducted at least once every 60 days 
(or other frequency approved by the Regional Supervisor);
    (2) Follow the well test procedures in 30 CFR part 250, Subpart K; 
and
    (3) Retain the well test data at the field location for 2 years.

Sec.  250.1205  Site security.

    (a) What are the requirements for site security? You must:
    (1) Protect Federal production against production loss or theft;
    (2) Post a sign at each royalty or inventory tank which is used in 
the royalty determination process. The sign must contain the name of 
the facility operator, the size of the tank, and the tank number;
    (3) Not bypass BSEE-approved liquid hydrocarbon royalty meters and 
tanks; and
    (4) Report the following to the Regional Supervisor as soon as 
possible, but no later than the next business day after discovery:
    (i) Theft or mishandling of production;
    (ii) Tampering or bypassing any component of the royalty 
measurement facility; and
    (iii) Falsifying production measurements.
    (b) What are the requirements for using seals? You must:
    (1) Seal the following components of liquid hydrocarbon royalty 
meter installations to ensure that tampering cannot occur without 
destroying the seal:
    (i) Meter component connections from the base of the meter up to 
and including the register;
    (ii) Sampling systems including packing device, fittings, sight 
glass, and container lid;
    (iii) Temperature and gravity compensation device components;
    (iv) All valves on lines leaving a royalty or inventory storage 
tank, including load-out line valves, drain-line valves, and 
connection-line valves between royalty and non-royalty tanks; and
    (v) Any additional components required by the Regional Supervisor.
    (2) Seal all bypass valves of gas royalty and allocation meters.
    (3) Number and track the seals and keep the records at the field 
location for at least 2 years; and
    (4) Make the records of seals available for BSEE inspection.

Subpart M--Unitization

Sec.  250.1300  What is the purpose of this subpart?

    This subpart explains how Outer Continental Shelf (OCS) leases are 
unitized. If you are an OCS lessee, use the regulations in this subpart 
for both competitive reservoir and unitization situations. The purpose 
of joint development and unitization is to:
    (a) Conserve natural resources;
    (b) Prevent waste; and/or
    (c) Protect correlative rights, including Federal royalty 
interests.

Sec.  250.1301  What are the requirements for unitization?

    (a) Voluntary unitization. You and other OCS lessees may ask the 
Regional Supervisor to approve a request for voluntary unitization. The 
Regional Supervisor may approve the request for voluntary unitization 
if unitized operations:
    (1) Promote and expedite exploration and development; or
    (2) Prevent waste, conserve natural resources, or protect 
correlative rights, including Federal royalty interests, of a 
reasonably delineated and productive reservoir.
    (b) Compulsory unitization. The Regional Supervisor may require you 
and other lessees to unitize operations of a reasonably delineated and 
productive reservoir if unitized operations are necessary to:
    (1) Prevent waste;
    (2) Conserve natural resources; or
    (3) Protect correlative rights, including Federal royalty 
interests.
    (c) Unit area. The area that a unit includes is the minimum number 
of leases that will allow the lessees to minimize the number of 
platforms, facility installations, and wells necessary for efficient 
exploration, development, and production of mineral deposits, oil and 
gas reservoirs, or potential hydrocarbon accumulations common to two or 
more leases. A unit may include whole leases or portions of leases.
    (d) Unit agreement. You, the other lessees, and the unit operator 
must enter into a unit agreement. The unit agreement must: allocate 
benefits to unitized leases, designate a unit operator, and specify the 
effective date of the unit agreement. The unit agreement must terminate 
when: the unit no longer produces unitized

[[Page 64570]]

substances, and the unit operator no longer conducts drilling or well-
workover operations (Sec.  250.180) under the unit agreement, unless 
the Regional Supervisor orders or approves a suspension of production 
under Sec.  250.170.
    (e) Unit operating agreement. The unit operator and the owners of 
working interests in the unitized leases must enter into a unit 
operating agreement. The unit operating agreement must describe how all 
the unit participants will apportion all costs and liabilities incurred 
maintaining or conducting operations. When a unit involves one or more 
net-profit-share leases, the unit operating agreement must describe how 
to attribute costs and credits to the net-profit-share lease(s), and 
this part of the agreement must be approved by the Regional Supervisor. 
Otherwise, you must provide a copy of the unit operating agreement to 
the Regional Supervisor, but the Regional Supervisor does not need to 
approve the unit operating agreement.
    (f) Extension of a lease covered by unit operations. If your unit 
agreement expires or terminates, or the unit area adjusts so that no 
part of your lease remains within the unit boundaries, your lease 
expires unless:
    (1) Its initial term has not expired;
    (2) You conduct drilling, production, or well-reworking operations 
on your lease consistent with applicable regulations; or
    (3) BSEE orders or approves a suspension of production or 
operations for your lease.
    (g) Unit operations. If your lease, or any part of your lease, is 
subject to a unit agreement, the entire lease continues for the term 
provided in the lease, and as long thereafter as any portion of your 
lease remains part of the unit area, and as long as operations continue 
the unit in effect.
    (1) If you drill, produce or perform well-workover operations on a 
lease within a unit, each lease, or part of a lease, in the unit will 
remain active in accordance with the unit agreement. Following a 
discovery, if your unit ceases drilling activities for a reasonable 
time period between the delineation of one or more reservoirs and the 
initiation of actual development drilling or production operations and 
that time period would extend beyond your lease's primary term or any 
extension under Sec.  250.180, the unit operator must request and 
obtain BSEE approval of a suspension of production under Sec.  250.170 
in order to keep the unit from terminating.
    (2) When a lease in a unit agreement is beyond the primary term and 
the lease or unit is not producing, the lease will expire unless:
    (i) You conduct a continuous drilling or well reworking program 
designed to develop or restore the lease or unit production; or
    (ii) BSEE orders or approves a suspension of operations under Sec.  
250.170.

Sec.  250.1302  What if I have a competitive reservoir on a lease?

    (a) The Regional Supervisor may require you to conduct development 
and production operations in a competitive reservoir under either a 
joint Development and Production Plan, submitted to BOEM or a 
unitization agreement. A competitive reservoir has one or more 
producing or producible well completions on each of two or more leases, 
or portions of leases, with different lease operating interests. For 
purposes of this paragraph, a producible well completion is a well 
which is capable of production and which is shut in at the well head or 
at the surface but not necessarily connected to production facilities 
and from which the operator plans future production.
    (b) You may request that the Regional Supervisor make a preliminary 
determination whether a reservoir is competitive. When you receive the 
preliminary determination, you have 30 days (or longer if the Regional 
Supervisor allows additional time) to concur or to submit an objection 
with supporting evidence if you do not concur. The Regional Supervisor 
will make a final determination and notify you and the other lessees.
    (c) If you conduct drilling or production operations in a reservoir 
determined competitive by the Regional Supervisor, you and the other 
affected lessees must submit for approval a joint plan of operations. 
You must submit the joint plan within 90 days after the Regional 
Supervisor makes a final determination that the reservoir is 
competitive. The joint plan must provide for the development and/or 
production of the reservoir. You may submit supplemental plans for the 
Regional Supervisor's approval.
    (d) If you and the other affected lessees cannot reach an agreement 
on a joint Development and Production Plan, submitted to BOEM within 
the approved period of time, each lessee must submit a separate plan to 
the Regional Supervisor. The Regional Supervisor will hold a hearing to 
resolve differences in the separate plans. If the differences in the 
separate plans are not resolved at the hearing and the Regional 
Supervisor determines that unitization is necessary under Sec.  
250.1301(b), BSEE will initiate unitization under Sec.  250.1304.

Sec.  250.1303  How do I apply for voluntary unitization?

    (a) You must file a request for a voluntary unit with the Regional 
Supervisor. Your request must include:
    (1) A draft of the proposed unit agreement;
    (2) A proposed initial plan of operation;
    (3) Supporting geological, geophysical, and engineering data; and
    (4) Other information that may be necessary to show that the 
unitization proposal meets the criteria of Sec.  250.1300.
    (b) The unit agreement must comply with the requirements of this 
part. BSEE will maintain and provide a model unit agreement for you to 
follow. If BSEE revises the model, BSEE will publish the revised model 
in the Federal Register. If you vary your unit agreement from the model 
agreement, you must obtain the approval of the Regional Supervisor.
    (c) After the Regional Supervisor accepts your unitization 
proposal, you, the other lessees, and the unit operator must sign and 
file copies of the unit agreement, the unit operating agreement, and 
the initial plan of operation with the Regional Supervisor for 
approval.
    (d) You must pay the service fee listed in Sec.  250.125 of this 
part with your request for a voluntary unitization proposal or the 
expansion of a previously approved voluntary unit to include additional 
acreage. Additionally, you must pay the service fee listed in Sec.  
250.125 with your request for unitization revision.

Sec.  250.1304  How will BSEE require unitization?

    (a) If the Regional Supervisor determines that unitization of 
operations within a proposed unit area is necessary to prevent waste, 
conserve natural resources of the OCS, or protect correlative rights, 
including Federal royalty interests, the Regional Supervisor may 
require unitization.
    (b) If you ask BSEE to require unitization, you must file a request 
with the Regional Supervisor. You must include a proposed unit 
agreement as described in Sec. Sec.  250.1301(d) and 250.1303(b); a 
proposed unit operating agreement; a proposed initial plan of 
operation; supporting geological, geophysical, and engineering data; 
and any other information that may be necessary to show that 
unitization meets the criteria of Sec.  250.1300. The proposed unit 
agreement must include a

[[Page 64571]]

counterpart executed by each lessee seeking compulsory unitization. 
Lessees who seek compulsory unitization must simultaneously serve on 
the nonconsenting lessees copies of:
    (1) The request;
    (2) The proposed unit agreement with executed counterparts;
    (3) The proposed unit operating agreement; and
    (4) The proposed initial plan of operation.
    (c) If the Regional Supervisor initiates compulsory unitization, 
BSEE will serve all lessees of the proposed unit area with a proposed 
unitization plan and a statement of reasons for the proposed 
unitization.
    (d) The Regional Supervisor will not require unitization until BSEE 
provides all lessees of the proposed unit area written notice and an 
opportunity for a hearing. If you want BSEE to hold a hearing, you must 
request it within 30 days after you receive written notice from the 
Regional Supervisor or after you are served with a request for 
compulsory unitization from another lessee.
    (e) BSEE will not hold a hearing under this paragraph until at 
least 30 days after BSEE provides written notice of the hearing date to 
all parties owning interests that would be made subject to the unit 
agreement. The Regional Supervisor must give all lessees of the 
proposed unit area an opportunity to submit views orally and in writing 
and to question both those seeking and those opposing compulsory 
unitization. Adjudicatory procedures are not required. The Regional 
Supervisor will make a decision based upon a record of the hearing, 
including any written information made a part of the record. The 
Regional Supervisor will arrange for a court reporter to make a 
verbatim transcript. The party seeking compulsory unitization must pay 
for the court reporter and pay for and provide to the Regional 
Supervisor within 10 days after the hearing three copies of the 
verbatim transcript.
    (f) The Regional Supervisor will issue an order that requires or 
rejects compulsory unitization. That order must include a statement of 
reasons for the action taken and identify those parts of the record 
which form the basis of the decision. Any adversely affected party may 
appeal the final order of the Regional Supervisor under 30 CFR part 
290.

Subpart N--Outer Continental Shelf Civil Penalties

Outer Continental Shelf Lands Act Civil Penalties

Sec.  250.1400  How does BSEE begin the civil penalty process?

    This subpart explains BSEEs civil penalty procedures whenever a 
lessee, operator or other person engaged in oil, gas, sulphur or other 
minerals operations in the OCS has a violation. Whenever BSEE 
determines, on the basis of available evidence, that a violation 
occurred and a civil penalty review is appropriate, it will prepare a 
case file. BSEE will appoint a Reviewing Officer.

Sec.  250.1401  Index table.

    The following table is an index of the sections in this subpart:

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

Sec.  250.1402  Definitions.

    Terms used in this subpart have the following meaning:
    Case file means a BSEE document file containing information and the 
record of evidence related to the alleged violation.
    Civil penalty means a fine. It is a BSEE regulatory enforcement 
tool used in addition to Notices of Incidents of Noncompliance and 
directed suspensions of production or other operations.
    Reviewing Officer means a BSEE employee assigned to review case 
files and assess civil penalties.
    Violation means failure to comply with the Outer Continental Shelf 
Lands Act (OCSLA) or any other applicable laws, with any regulations 
issued under the OCSLA, or with the terms or provisions of leases, 
licenses, permits, rights-of-way, or other approvals issued under the 
OCSLA.
    Violator means a person responsible for a violation.

Sec.  250.1403  What is the maximum civil penalty?

    The maximum civil penalty is $40,000 per day per violation.

Sec.  250.1404  Which violations will BSEE review for potential civil 
penalties?

    BSEE will review each of the following violations for potential 
civil penalties:
    (a) Violations that you do not correct within the period BSEE 
grants;
    (b) Violations that BSEE determines may constitute, or constituted, 
a threat of serious, irreparable, or immediate harm or damage to life 
(including fish and other aquatic life), property, any mineral deposit, 
or the marine, coastal, or human environment; or
    (c) Violations that cause serious, irreparable, or immediate harm 
or damage to life (including fish and other aquatic life), property, 
any mineral deposit, or the marine, coastal, or human environment.
    (d) Violations of the oil spill financial responsibility 
requirements at 30 CFR part 553.

Sec.  250.1405  When is a case file developed?

    BSEE will develop a case file during its investigation of the 
violation, and forward it to a Reviewing Officer if any of the 
conditions in Sec.  250.1404 exist. The Reviewing Officer will review 
the case file and determine if a civil penalty is appropriate. The 
Reviewing Officer may administer oaths and issue subpoenas requiring 
witnesses to attend meetings, submit depositions, or produce evidence.

Sec.  250.1406  When will BSEE notify me and provide penalty 
information?

    If the Reviewing Officer determines that a civil penalty should be 
assessed, the Reviewing Officer will send the violator a letter of 
notification. The letter of notification will include:
    (a) The amount of the proposed civil penalty;
    (b) Information on the violation(s); and
    (c) Instruction on how to obtain a copy of the case file, schedule 
a meeting, submit information, or pay the penalty.

Sec.  250.1407  How do I respond to the letter of notification?

    You have 30 calendar days after you receive the Reviewing Officer's 
letter to either:
    (a) Request, in writing, a meeting with the Reviewing Officer;
    (b) Submit additional information; or
    (c) Pay the proposed civil penalty.

[[Page 64572]]

Sec.  250.1408  When will I be notified of the Reviewing Officer's 
decision?

    At the end of the 30 calendar days or after the meeting and 
submittal of additional information, the Reviewing Officer will review 
the case file, including all information you submitted, and send you a 
decision. The decision will include the amount of any final civil 
penalty, the basis for the civil penalty, and instructions for paying 
or appealing the civil penalty.

Sec.  250.1409  What are my appeal rights?

    (a) When you receive the Reviewing Officer's final decision, you 
have 60 days to either pay the penalty or file an appeal in accordance 
with 30 CFR part 290, subpart A.
    (b) If you file an appeal, you must either:
    (1) Submit a surety bond in the amount of the penalty to the 
appropriate Leasing Office in the Region where the penalty was 
assessed, following instructions that the Reviewing Officer will 
include in the final decision; or
    (2) Notify the appropriate Leasing Office, in the Region where the 
penalty was assessed, that you want your lease-specific/area-wide bond 
on file to be used as the bond for the penalty amount.
    (c) If you choose the alternative in paragraph (b)(2) of this 
section, the BOEM Regional Director may require additional security 
(i.e., security in excess of your existing bond) to ensure sufficient 
coverage during an appeal. In that event, the Regional Director will 
require you to post the supplemental bond with the regional office in 
the same manner as under 30 CFR 556.53(d) through (f). If the Regional 
Director determines the appeal should be covered by a lease-specific 
abandonment account then you must establish an account that meets the 
requirements of 30 CFR part 556.56.
    (d) If you do not either pay the penalty or file a timely appeal, 
BSEE will take one or more of the following actions:
    (1) We will collect the amount you were assessed, plus interest, 
late payment charges, and other fees as provided by law, from the date 
you received the Reviewing Officer's final decision until the date we 
receive payment;
    (2) We may initiate additional enforcement, including, if 
appropriate, cancellation of the lease, right-of-way, license, permit, 
or approval, or the forfeiture of a bond under this part; or
    (3) We may bar you from doing further business with the Federal 
Government according to Executive Orders 12549 and 12689, and section 
2455 of the Federal Acquisition Streamlining Act of 1994, 31 U.S.C. 
6101. The Department of the Interior's regulations implementing these 
authorities are found at 43 CFR part 12, subpart D.

Federal Oil and Gas Royalty Management Act Civil Penalties Definitions

Sec.  250.1450  What definitions apply to this subpart?

    The terms used in this subpart have the same meaning as in 30 
U.S.C. 1702.

Penalties After a Period To Correct

Sec.  250.1451  What may BSEE do if I violate a statute, regulation, 
order, or lease term relating to a Federal oil and gas lease?

    (a) If we believe that you have not followed any requirement of a 
statute, regulation, order, or lease term for any Federal oil or gas 
lease, we may send you a Notice of Noncompliance informing you what the 
violation is and what you need to do to correct it to avoid civil 
penalties under 30 U.S.C. 1719(a) and (b).
    (b) We will serve the Notice of Noncompliance by registered mail or 
personal service using the most current address on file as maintained 
by the BOEM Leasing Office in your respective Region.

Sec.  250.1452  What if I correct the violation?

    The matter will be closed if you correct all of the violations 
identified in the Notice of Noncompliance within 20 days after you 
receive the Notice (or within a longer time period specified in the 
Notice).

Sec.  250.1453  What if I do not correct the violation?

    (a) We may send you a Notice of Civil Penalty if you do not correct 
all of the violations identified in the Notice of Noncompliance within 
20 days after you receive the Notice of Noncompliance (or within a 
longer time period specified in that Notice). The Notice of Civil 
Penalty will tell you how much penalty you must pay. The penalty may be 
up to $500 per day, beginning with the date of the Notice of 
Noncompliance, for each violation identified in the Notice of 
Noncompliance for as long as you do not correct the violations.
    (b) If you do not correct all of the violations identified in the 
Notice of Noncompliance within 40 days after you receive the Notice of 
Noncompliance (or 20 days following the expiration of a longer time 
period specified in that Notice), we may increase the penalty to up to 
$5,000 per day, beginning with the date of the Notice of Noncompliance, 
for each violation for as long as you do not correct the violations.

Sec.  250.1454  How may I request a hearing on the record on a Notice 
of Noncompliance?

    You may request a hearing on the record on a Notice of 
Noncompliance by filing a request within 30 days of the date you 
received the Notice of Noncompliance with the Hearings Division 
(Departmental), Office of Hearings and Appeals, U.S. Department of the 
Interior, 801 North Quincy Street, Arlington, Virginia 22203. You may 
do this regardless of whether you correct the violations identified in 
the Notice of Noncompliance.

Sec.  250.1455  Does my request for a hearing on the record affect the 
penalties?

    (a) If you do not correct the violations identified in the Notice 
of Noncompliance, the penalties will continue to accrue even if you 
request a hearing on the record.
    (b) You may petition the Hearings Division (Departmental) of the 
Office of Hearings and Appeals, to stay the accrual of penalties 
pending the hearing on the record and a decision by the Administrative 
Law Judge under Sec.  250.1472.
    (1) You must file your petition within 45 calendar days of 
receiving the Notice of Noncompliance.
    (2) To stay the accrual of penalties, you must post a bond or other 
surety instrument, or demonstrate financial solvency, using the 
standards and requirements as prescribed in Sec. Sec.  250.1490 through 
250.1497, for the principal amount of any unpaid amounts due that are 
the subject of the Notice of Noncompliance, including interest thereon, 
plus the amount of any penalties accrued before the date a stay becomes 
effective.
    (3) The Hearings Division will grant or deny the petition under 43 
CFR 4.21(b).

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

    (a) You may request a hearing on the record to challenge only the 
amount of a civil penalty when you receive a Notice of Civil Penalty, 
if you did not previously request a hearing on the record under Sec.  
250.1454. If you did not request a hearing on the record on the Notice 
of Noncompliance under Sec.  250.1454, you may not contest your 
underlying liability for civil penalties.
    (b) You must file your request within 10 days after you receive the 
Notice of Civil Penalty with the Hearings Division (Departmental), 
Office of Hearings and

[[Page 64573]]

Appeals, U.S. Department of the Interior, 801 North Quincy Street, 
Arlington, Virginia 22203.

Penalties Without a Period To Correct

Sec.  250.1460  May I be subject to penalties without prior notice and 
an opportunity to correct?

    The Federal Oil and Gas Royalty Management Act sets out several 
specific violations for which penalties accrue without an opportunity 
to first correct the violation.
    (a) Under 30 U.S.C. 1719(c), you may be subject to penalties of up 
to $10,000 per day per violation for each day the violation continues 
if you:
    (1) Fail or refuse to permit lawful entry, inspection, or audit; or
    (2) Knowingly or willfully fail or refuse to notify the Secretary, 
within 5 business days after any well begins production on a lease site 
or allocated to a lease site, or resumes production in the case of a 
well which has been off production for more than 90 days, of the date 
on which production has begun or resumed.
    (b) Under 30 U.S.C. 1719(d), you may be subject to civil penalties 
of up to $25,000 per day for each day each violation continues if you:
    (1) Knowingly or willfully prepare, maintain, or submit false, 
inaccurate, or misleading reports, notices, affidavits, records, data, 
or other written information;
    (2) Knowingly or willfully take or remove, transport, use or divert 
any oil or gas from any lease site without having valid legal authority 
to do so; or
    (3) Purchase, accept, sell, transport, or convey to another person, 
any oil or gas knowing or having reason to know that such oil or gas 
was stolen or unlawfully removed or diverted.

Sec.  250.1461  How will BSEE inform me of violations without a period 
to correct?

    We will inform you of any violation, without a period to correct, 
by issuing a Notice of Noncompliance and Civil Penalty explaining the 
violation, how to correct it, and the penalty assessment. We will serve 
the Notice of Noncompliance and Civil Penalty by registered mail or 
personal service using your address of record as specified under 30 CFR 
part 1218, Subpart H.

Sec.  250.1462  How may I request a hearing on the record on a Notice 
of Noncompliance regarding violations without a period to correct?

    You may request a hearing on the record of a Notice of 
Noncompliance regarding violations without a period to correct by 
filing a request within 30 days after you receive the Notice of 
Noncompliance with the Hearings Division (Departmental), Office of 
Hearings and Appeals, U.S. Department of the Interior, 801 North Quincy 
Street, Arlington, Virginia 22203. You may do this regardless of 
whether you correct the violations identified in the Notice of 
Noncompliance.

Sec.  250.1463  Does my request for a hearing on the record affect the 
penalties?

    (a) If you do not correct the violations identified in the Notice 
of Noncompliance regarding violations without a period to correct, the 
penalties will continue to accrue even if you request a hearing on the 
record.
    (b) You may ask the Hearings Division (Departmental) to stay the 
accrual of penalties pending the hearing on the record and a decision 
by the Administrative Law Judge under Sec.  250.1472.
    (1) You must file your petition within 45 calendar days after you 
receive the Notice of Noncompliance.
    (2) To stay the accrual of penalties, you must post a bond or other 
surety instrument, or demonstrate financial solvency, using the 
standards and requirements as prescribed in Sec. Sec.  250.1490 through 
250.1497, for the principal amount of any unpaid amounts due that are 
the subject of the Notice of Noncompliance, including interest thereon, 
plus the amount of any penalties accrued before the date a stay becomes 
effective.
    (3) The Hearings Division will grant or deny the petition under 43 
CFR 4.21(b).

Sec.  250.1464  May I request a hearing on the record regarding the 
amount of a civil penalty if I did not request a hearing on the Notice 
of Noncompliance?

    (a) You may request a hearing on the record to challenge only the 
amount of a civil penalty when you receive a Notice of Civil Penalty 
regarding violations without a period to correct, if you did not 
previously request a hearing on the record under Sec.  250.1462. If you 
did not request a hearing on the record on the Notice of Noncompliance 
under Sec.  250.1462, you may not contest your underlying liability for 
civil penalties.
    (b) You must file your request within 10 days after you receive 
Notice of Civil Penalty with the Hearings Division (Departmental), 
Office of Hearings and Appeals, U.S. Department of the Interior, 801 
North Quincy, Arlington, Virginia 22203.

General Provisions

Sec.  250.1470  How does BSEE decide what the amount of the penalty 
should be?

    We determine the amount of the penalty by considering the severity 
of the violations, your history of compliance, and if you are a small 
business.

Sec.  250.1471  Does the penalty affect whether I owe interest?

    If you do not pay the penalty by the date required under Sec.  
250.1475(d), BSEE will assess you late payment interest on the penalty 
amount at the same rate interest is assessed under 30 CFR 1218.54.

Sec.  250.1472  How will the Office of Hearings and Appeals conduct the 
hearing on the record?

    If you request a hearing on the record under Sec. Sec.  250.1454, 
250.1456, 250.1462, or 250.1464, the hearing will be conducted by a 
Departmental Administrative Law Judge from the Office of Hearings and 
Appeals. After the hearing, the Administrative Law Judge will issue a 
decision in accordance with the evidence presented and applicable law.

Sec.  250.1473  How may I appeal the Administrative Law Judge's 
decision?

    If you are adversely affected by the Administrative Law Judge's 
decision, you may appeal that decision to the Interior Board of Land 
Appeals under 43 CFR part 4, subpart E.

Sec.  250.1474  May I seek judicial review of the decision of the 
Interior Board of Land Appeals?

    Under 30 U.S.C. 1719(j), you may seek judicial review of the 
decision of the Interior Board of Land Appeals. A suit for judicial 
review in the District Court will be barred unless filed within 90 days 
after the final order.

Sec.  250.1475  When must I pay the penalty?

    (a) You must pay the amount of the Notice of Civil Penalty issued 
under Sec. Sec.  250.1453 or 250.1461, if you do not request a hearing 
on the record under Sec. Sec.  250.1454, 250.1456, 250.1462, or 
250.1464.
    (b) If you request a hearing on the record under Sec. Sec.  
250.1454, 250.1456, 250.1462, or 250.1464, but you do not appeal the 
determination of the Administrative Law Judge to the Interior Board of 
Land Appeals under Sec.  250.1473, you must pay the amount assessed by 
the Administrative Law Judge.
    (c) If you appeal the determination of the Administrative Law Judge 
to the Interior Board of Land Appeals, you must pay the amount assessed 
in the IBLA decision.
    (d) You must pay the penalty assessed within 40 days after:
    (1) You received the Notice of Civil Penalty, if you did not 
request a hearing

[[Page 64574]]

on the record under either Sec. Sec.  250.1454, 250.1456, 250.1462, or 
250.1464;
    (2) You received an Administrative Law Judge's decision under Sec.  
250.1472, if you obtained a stay of the accrual of penalties pending 
the hearing on the record under Sec.  250.1455(b) or Sec.  250.1463(b) 
and did not appeal the Administrative Law Judge's determination to the 
IBLA under Sec.  250.1473;
    (3) You received an IBLA decision under Sec.  250.1473 if the IBLA 
continued the stay of accrual of penalties pending its decision and you 
did not seek judicial review of the IBLA's decision; or
    (4) A final non-appealable judgment of a court of competent 
jurisdiction is entered, if you sought judicial review of the IBLA's 
decision and the Department or the appropriate court suspended 
compliance with the IBLA's decision pending the adjudication of the 
case.
    (e) If you do not pay, that amount is subject to collection under 
the provisions of Sec.  250.1477.

Sec.  250.1476  Can BSEE reduce my penalty once it is assessed?

    Under 30 U.S.C. 1719(g), the Director or his or her delegate may 
compromise or reduce civil penalties assessed under this part.

Sec.  250.1477  How may BSEE collect the penalty?

    (a) BSEE may use all available means to collect the penalty 
including, but not limited to:
    (1) Requiring the lease surety, for amounts owed by lessees, to pay 
the penalty;
    (2) Deducting the amount of the penalty from any sums the United 
States owes to you; and
    (3) Using judicial process to compel your payment under 30 U.S.C. 
1719(k).
    (b) If the Department uses judicial process, or if you seek 
judicial review under Sec.  250.1474 and the court upholds assessment 
of a penalty, the court shall have jurisdiction to award the amount 
assessed plus interest assessed from the date of the expiration of the 
90-day period referred to in Sec.  250.1474. The amount of any penalty, 
as finally determined, may be deducted from any sum owing to you by the 
United States.

Criminal Penalties

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

    If you commit an act for which a civil penalty is provided at 30 
U.S.C. 1719(d) and Sec.  250.1460(b), the United States may pursue 
criminal penalties as provided at 30 U.S.C. 1720, in addition to any 
authority for prosecution under other statutes.

Bonding Requirements

Sec.  250.1490  What standards must my BOEM-specified surety instrument 
meet?

    (a) A BOEM-specified surety instrument must be in a form specified 
in BOEM instructions. BSEE will give you written information and 
standard forms for BOEM-specified surety instrument requirements.
    (b) BOEM will use a bank-rating service to determine whether a 
financial institution has an acceptable rating to provide a surety 
instrument adequate to indemnify the lessor from loss or damage.
    (1) Administrative appeal bonds must be issued by a qualified 
surety company which the Department of the Treasury has approved.
    (2) Irrevocable letters of credit or certificates of deposit must 
be from a financial institution acceptable to BOEM with a minimum 1-
year period of coverage subject to automatic renewal up to 5 years.

Sec.  250.1491  How will BOEM determine the amount of my bond or other 
surety instrument?

    (a) The BOEM bond-approving officer may approve your surety if he 
or she determines that the amount is adequate to guarantee payment. The 
amount of your surety may vary depending on the form of the surety and 
how long the surety is effective.
    (1) The amount of the BOEM-specified surety instrument must include 
the principal amount owed under the Notice of Noncompliance or Notice 
of Civil Penalty plus any accrued interest we determine is owed plus 
projected interest for a 1-year period.
    (2) Treasury book-entry bond or note amounts must be equal to at 
least 120 percent of the required surety amount.
    (b) If your appeal is not decided within 1 year from the filing 
date, you must increase the surety amount to cover additional estimated 
interest for another 1-year period. You must continue to do this 
annually on the date your appeal was filed. We will determine the 
additional estimated interest and notify you of the amount so you can 
amend your surety instrument.
    (c) You may submit a single surety instrument that covers multiple 
appeals. You may change the instrument to add new amounts under appeal 
or remove amounts that have been adjudicated in your favor or that you 
have paid, if you:
    (1) Amend the single surety instrument annually on the date you 
filed your first appeal; and
    (2) Submit a separate surety instrument for new amounts under 
appeal until you amend the instrument to cover the new appeals.

Financial Solvency Requirements

Sec.  250.1495  How do I demonstrate financial solvency?

    (a) To demonstrate financial solvency under this part, you must 
submit an audited consolidated balance sheet, and, if requested by the 
BOEM bond-approving officer, up to 3 years of tax returns to BOEM using 
the U.S. Postal Service, private delivery, courier, or overnight 
delivery at:
    (1) For Alaska OCS: Jeffrey Walker, RS/FO, BOEM Alaska OCS Region, 
3801 Centerpoint Drive, Suite 500, Anchorage, AK 99503-5823, 
jeffrey.walker@boem.gov, (907) 334-5300.
    (2) For Gulf of Mexico and Atlantic OCS: Joshua Joyce, Regional 
FARM Program Coordinator, BOEM Gulf of Mexico OCS Region, 1201 Elmwood 
Park Boulevard New Orleans, LA 70123-2394, joshua.joyce@boem.gov, (504) 
736-2779.
    (3) For Pacific OCS: Jaron Ming, Lead Leasing Specialist, BOEM 
Pacific OCS Region, 770 Paseo Camarillo, 2nd Floor, Camarillo, CA 
93010, jaron.ming@boem.gov, (805) 389-7514.
    (b) You must submit an audited consolidated balance sheet annually, 
and, if requested, additional annual tax returns on the date BSEE first 
determined that you demonstrated financial solvency as long as you have 
active appeals, or whenever BSEE requests.
    (c) If you demonstrate financial solvency in the current calendar 
year, you are not required to redemonstrate financial solvency for new 
appeals of orders during that calendar year unless you file for 
protection under any provision of the U.S. Bankruptcy Code (Title 11 of 
the United States Code), or BSEE notifies you that you must 
redemonstrate financial solvency.

Sec.  250.1496  How will BOEM determine if I am financially solvent?

    (a) The BOEM bond-approving officer will determine your financial 
solvency by examining your total net worth, including, as appropriate, 
the net worth of your affiliated entities.
    (b) If your net worth, minus the amount we would require as surety 
under Sec. Sec.  250.1490 and 250.1491 for all orders you have appealed 
is greater than $300 million, you are presumptively deemed financially 
solvent, and we will not require you to post a bond or other surety 
instrument.

[[Page 64575]]

    (c) If your net worth, minus the amount we would require as surety 
under Sec. Sec.  250.1490 and 250.1491 for all orders you have appealed 
is less than $300 million, you must submit the following to BSEE by one 
of the methods in Sec.  250.1495(a):
    (1) A written request asking us to consult a business-information, 
or credit-reporting service or program to determine your financial 
solvency; and
    (2) A nonrefundable $50 processing fee:
    (i) You must pay the processing fee to us following the 
requirements for making payments found in 30 CFR 250.126. You are 
required to use Electronic Funds Transfer (EFT) for these payments;
    (ii) You must submit the fee with your request under paragraph 
(c)(1) of this section, and then annually on the date we first 
determined that you demonstrated financial solvency, as long as you are 
not able to demonstrate financial solvency under paragraph (a) of this 
section and you have active appeals.
    (d) If you request that we consult a business-information or 
credit-reporting service or program under paragraph (c) of this 
section:
    (1) We will use criteria similar to that which a potential creditor 
would use to lend an amount equal to the bond or other surety 
instrument we would require under Sec. Sec.  250.1490 and 250.1491;
    (2) For us to consider you financially solvent, the business-
information or credit-reporting service or program must demonstrate 
your degree of risk as low to moderate:
    (i) If our bond-approving officer determines that the business-
information or credit-reporting service or program information 
demonstrates your financial solvency to our satisfaction, our bond-
approving officer will not require you to post a bond or other surety 
instrument under Sec. Sec.  250.1490 and 250.1491;
    (ii) If our bond-approving officer determines that the business-
information or credit-reporting service or program information does not 
demonstrate your financial solvency to our satisfaction, our bond-
approving officer will require you to post a bond or other surety 
instrument under Sec. Sec.  250.1490 and 250.1491 or pay the 
obligation.

Sec.  250.1497  When will BOEM monitor my financial solvency?

    (a) If you are presumptively financially solvent under Sec.  
250.1496(b), BOEM will determine your net worth as described under 
Sec.  250.1496(b) and (c) to evaluate your financial solvency at least 
annually on the date we first determined that you demonstrated 
financial solvency as long as you have active appeals and each time you 
appeal a new order.
    (b) If you ask us to consult a business-information or credit-
reporting service or program under Sec.  250.1496(c), we will consult a 
service or program annually as long as you have active appeals and each 
time you appeal a new order.
    (c) If our bond-approving officer determines that you are no longer 
financially solvent, you must post a bond or other BOEM-specified 
surety instrument under Sec. Sec.  250.1490 and 250.1491.

Subpart O--Well Control and Production Safety Training

Sec.  250.1500  Definitions.

    Terms used in this subpart have the following meaning:
    Contractor and contract personnel mean anyone, other than an 
employee of the lessee, performing well control, deepwater well 
control, or production safety duties for the lessee.
    Deepwater well control means well control when you are using a 
subsea BOP system.
    Employee means direct employees of the lessees who are assigned 
well control, deepwater well control, or production safety duties.
    I or you means the lessee engaged in oil, gas, or sulphur 
operations in the Outer Continental Shelf (OCS).
    Lessee means a person who has entered into a lease with the United 
States to explore for, develop, and produce the leased minerals. The 
term lessee also includes an owner of operating rights for that lease 
and the BOEM-approved assignee of that lease.
    Periodic means occurring or recurring at regular intervals. Each 
lessee must specify the intervals for periodic training and periodic 
assessment of training needs in their training programs.
    Production operations include, but are not limited to, separation, 
dehydration, compression, sweetening, and metering operations.
    Production safety includes measures, practices, procedures, and 
equipment to ensure safe, accident-free, and pollution-free production 
operations, as well as installation, repair, testing, maintenance, and 
operation of surface and subsurface safety equipment.
    Well completion/well workover means those operations following the 
drilling of a well that are intended to establish or restore 
production.
    Well control means drilling, well completion, well workover, and 
well servicing operations. For purposes of this subpart, well 
completion/well workover means those operations following the drilling 
of a well that are intended to establish or restore production to a 
well. It includes small tubing operations but does not include well 
servicing.
    Well servicing means snubbing, coil tubing, and wireline 
operations.

Sec.  250.1501  What is the goal of my training program?

    The goal of your training program must be safe and clean OCS 
operations. To accomplish this, you must ensure that your employees and 
contract personnel engaged in well control, deepwater well control, or 
production safety operations understand and can properly perform their 
duties.

Sec.  250.1503  What are my general responsibilities for training?

    (a) You must establish and implement a training program so that all 
of your employees are trained to competently perform their assigned 
well control, deepwater well control, and production safety duties. You 
must verify that your employees understand and can perform the assigned 
well control, deepwater well control, or production safety duties.
    (b) If you conduct operations with a subsea BOP stack, your 
employees and contract personnel must be trained in deepwater well 
control. The trained employees and contract personnel must have a 
comprehensive knowledge of deepwater well control equipment, practices, 
and theory.
    (c) You must have a training plan that specifies the type, 
method(s), length, frequency, and content of the training for your 
employees. Your training plan must specify the method(s) of verifying 
employee understanding and performance. This plan must include at least 
the following information:
    (1) Procedures for training employees in well control, deepwater 
well control, or production safety practices;
    (2) Procedures for evaluating the training programs of your 
contractors;
    (3) Procedures for verifying that all employees and contractor 
personnel engaged in well control, deepwater well control, or 
production safety operations can perform their assigned duties;
    (4) Procedures for assessing the training needs of your employees 
on a periodic basis;
    (5) Recordkeeping and documentation procedures; and
    (6) Internal audit procedures.
    (d) Upon request of the District Manager or Regional Supervisor, 
you must provide:

[[Page 64576]]

    (1) Copies of training documentation for personnel involved in well 
control, deepwater well control, or production safety operations during 
the past 5 years; and
    (2) A copy of your training plan.

Sec.  250.1504  May I use alternative training methods?

    You may use alternative training methods. These methods may include 
computer-based learning, films, or their equivalents. This training 
should be reinforced by appropriate demonstrations and ``hands-on'' 
training. Alternative training methods must be conducted according to, 
and meet the objectives of, your training plan.

Sec.  250.1505  Where may I get training for my employees?

    You may get training from any source that meets the requirements of 
your training plan.

Sec.  250.1506  How often must I train my employees?

    You determine the frequency of the training you provide your 
employees. You must do all of the following:
    (a) Provide periodic training to ensure that employees maintain 
understanding of, and competency in, well control, deepwater well 
control, or production safety practices;
    (b) Establish procedures to verify adequate retention of the 
knowledge and skills that employees need to perform their assigned well 
control, deepwater well control, or production safety duties; and
    (c) Ensure that your contractors' training programs provide for 
periodic training and verification of well control, deepwater well 
control, or production safety knowledge and skills.

Sec.  250.1507  How will BSEE measure training results?

    BSEE may periodically assess your training program, using one or 
more of the methods in this section.
    (a) Training system audit. BSEE or its authorized representative 
may conduct a training system audit at your office. The training system 
audit will compare your training program against this subpart. You must 
be prepared to explain your overall training program and produce 
evidence to support your explanation.
    (b) Employee or contract personnel interviews. BSEE or its 
authorized representative may conduct interviews at either onshore or 
offshore locations to inquire about the types of training that were 
provided, when and where this training was conducted, and how effective 
the training was.
    (c) Employee or contract personnel testing. BSEE or its authorized 
representative may conduct testing at either onshore or offshore 
locations for the purpose of evaluating an individual's knowledge and 
skills in perfecting well control, deepwater well control, and 
production safety duties.
    (d) Hands-on production safety, simulator, or live well testing. 
BSEE or its authorized representative may conduct tests at either 
onshore or offshore locations. Tests will be designed to evaluate the 
competency of your employees or contract personnel in performing their 
assigned well control, deepwater well control, and production safety 
duties. You are responsible for the costs associated with this testing, 
excluding salary and travel costs for BSEE personnel.

Sec.  250.1508  What must I do when BSEE administers written or oral 
tests?

    BSEE or its authorized representative may test your employees or 
contract personnel at your worksite or at an onshore location. You and 
your contractors must:
    (a) Allow BSEE or its authorized representative to administer 
written or oral tests; and
    (b) Identify personnel by current position, years of experience in 
present position, years of total oil field experience, and employer's 
name (e.g., operator, contractor, or sub-contractor company name).

Sec.  250.1509  What must I do when BSEE administers or requires hands-
on, simulator, or other types of testing?

    If BSEE or its authorized representative conducts, or requires you 
or your contractor to conduct hands-on, simulator, or other types of 
testing, you must:
    (a) Allow BSEE or its authorized representative to administer or 
witness the testing;
    (b) Identify personnel by current position, years of experience in 
present position, years of total oil field experience, and employer's 
name (e.g., operator, contractor, or sub-contractor company name); and
    (c) Pay for all costs associated with the testing, excluding salary 
and travel costs for BSEE personnel.

Sec.  250.1510  What will BSEE do if my training program does not 
comply with this subpart?

    If BSEE determines that your training program is not in compliance, 
we may initiate one or more of the following enforcement actions:
    (a) Issue an Incident of Noncompliance (INC);
    (b) Require you to revise and submit to BSEE your training plan to 
address identified deficiencies;
    (c) Assess civil/criminal penalties; or
    (d) Initiate disqualification procedures.

Subpart P--Sulphur Operations

Sec.  250.1600  Performance standard.

    Operations to discover, develop, and produce sulphur in the OCS 
shall be in accordance with a BOEM-approved Exploration Plan or 
Development and Production Plan and shall be conducted in a manner to 
protect against harm or damage to life (including fish and other 
aquatic life), property, natural resources of the OCS including any 
mineral deposits (in areas leased or not leased), the National security 
or defense, and the marine, coastal, or human environment.

Sec.  250.1601  Definitions.

    Terms used in this subpart shall have the meanings as defined 
below:
    Air line means a tubing string that is used to inject air within a 
sulphur producing well to airlift sulphur out of the well.
    Bleedwater means a mixture of mine water or booster water and 
connate water that is produced by a bleedwell.
    Bleedwell means a well drilled into a producing sulphur deposit 
that is used to control the mine pressure generated by the injection of 
mine water.
    Brine means the water containing dissolved salt obtained from a 
brine well by circulating water into and out of a cavity in the salt 
core of a salt dome.
    Brine well means a well drilled through cap rock into the core at a 
salt dome for the purpose of producing brine.
    Cap rock means the rock formation, a body of limestone, anhydride, 
and/or gypsum, overlying a salt dome.
    Sulphur deposit means a formation of rock that contains elemental 
sulphur.
    Sulphur production rate means the number of long tons of sulphur 
produced during a certain period of time, usually per day.

Sec.  250.1602  Applicability.

    (a) The requirements of this subpart P are applicable to all 
exploration, development, and production operations under an OCS 
sulphur lease. Sulphur operations include all activities conducted 
under a lease for the purpose of discovery or delineation of a sulphur 
deposit and for the development and production of elemental sulphur. 
Sulphur operations also include activities conducted for related 
purposes. Activities conducted for related purposes include, but are 
not

[[Page 64577]]

limited to, production of other minerals, such as salt, for use in the 
exploration for or the development and production of sulphur. The 
lessee must have obtained the right to produce and/or use these other 
minerals.
    (b) Lessees conducting sulphur operations in the OCS shall comply 
with the requirements of the applicable provisions of subparts A, B, C, 
I, J, M, N, O, and Q of this part and the applicable provisions of 30 
CFR 550 subparts A, B, C, J and N.
    (c) Lessees conducting sulphur operations in the OCS are also 
required to comply with the requirements in the applicable provisions 
of subparts D, E, F, H, K, and L of this part and the applicable 
provisions of 30 CFR 550, subpart K, where such provisions specifically 
are referenced in this subpart.

Sec.  250.1603  Determination of sulphur deposit.

    (a) Upon receipt of a written request from the lessee, the District 
Manager will determine whether a sulphur deposit has been defined that 
contains sulphur in paying quantities (i.e., sulphur in quantities 
sufficient to yield a return in excess of the costs, after completion 
of the wells, of producing minerals at the wellheads).
    (b) A determination under paragraph (a) of this section shall be 
based upon the following:
    (1) Core analyses that indicate the presence of a producible 
sulphur deposit (including an assay of elemental sulphur);
    (2) An estimate of the amount of recoverable sulphur in long tons 
over a specified period of time; and
    (3) Contour map of the cap rock together with isopach map showing 
the extent and estimated thickness of the sulphur deposit.

Sec.  250.1604  General requirements.

    Sulphur lessees shall comply with requirements of this section when 
conducting well-drilling, well-completion, well-workover, or production 
operations.
    (a) Equipment movement. The movement of well-drilling, well-
completion, or well-workover rigs and related equipment on and off an 
offshore platform, or from one well to another well on the same 
offshore platform, including rigging up and rigging down, shall be 
conducted in a safe manner.
    (b) Hydrogen sulfide (H2S). When a drilling, well-completion, well-
workover, or production operation is being conducted on a well in zones 
known to contain H2S or in zones where the presence of 
H2S is unknown (as defined in Sec.  250.490 of this part), 
the lessee shall take appropriate precautions to protect life and 
property, especially during operations such as dismantling wellhead 
equipment and flow lines and circulating the well. The lessee shall 
also take appropriate precautions when H2S is generated as a 
result of sulphur production operations. The lessee shall comply with 
the requirements in Sec.  250.490 of this part as well as the 
requirements of this subpart.
    (c) Welding and burning practices and procedures. All welding, 
burning, and hot-tapping activities involved in drilling, well-
completion, well-workover or production operations shall be conducted 
with properly maintained equipment, trained personnel, and appropriate 
procedures in order to minimize the danger to life and property 
according to the specific requirements in Sec. Sec.  250.109 through 
250.113 of this part.
    (d) Electrical requirements. All electrical equipment and systems 
involved in drilling, well-completion, well-workover, and production 
operations shall be designed, installed, equipped, protected, operated, 
and maintained so as to minimize the danger to life and property in 
accordance with the requirements of Sec.  250.114 of this part.
    (e) Structures on fixed OCS platforms. Derricks, cranes, masts, 
substructures, and related equipment shall be selected, designed, 
installed, used, and maintained so as to be adequate for the potential 
loads and conditions of loading that may be encountered during the 
operations. Prior to moving equipment such as a well-drilling, well-
completion, or well-workover rig or associated equipment or production 
equipment onto a platform, the lessee shall determine the structural 
capability of the platform to safely support the equipment and 
operations, taking into consideration corrosion protection, platform 
age, and previous stresses.
    (f) Traveling-block safety device. All drilling units being used 
for drilling, well-completion, or well-workover operations that have 
both a traveling block and a crown block must be equipped with a safety 
device that is designed to prevent the traveling block from striking 
the crown block. The device must be checked for proper operation weekly 
and after each drill-line slipping operation. The results of the 
operational check must be entered in the operations log.

Sec.  250.1605  Drilling requirements.

    (a) Sulphur leases. Lessees of OCS sulphur leases shall conduct 
drilling operations in accordance with Sec. Sec.  250.1605 through 
250.1619 of this subpart and with other requirements of this part, as 
appropriate.
    (b) Fitness of drilling unit. (1) Drilling units shall be capable 
of withstanding the oceanographic and meteorological conditions for the 
proposed season and location of operations.
    (2) Prior to commencing operation, drilling units shall be made 
available for a complete inspection by the District Manager.
    (3) The lessee shall provide information and data on the fitness of 
the drilling unit to perform the proposed drilling operation. The 
information shall be submitted with, or prior to, the submission of 
Form BSEE-0123, Application for Permit to Drill (APD), in accordance 
with Sec.  250.1617 of this subpart. After a drilling unit has been 
approved by a BSEE district office, the information required in this 
paragraph need not be resubmitted unless required by the District 
Manager or there are changes in the equipment that affect the rated 
capacity of the unit.
    (c) Oceanographic, meteorological, and drilling unit performance 
data. Where oceanographic, meteorological, and drilling unit 
performance data are not otherwise readily available, lessees shall 
collect and report such data upon request to the District Manager. The 
type of information to be collected and reported will be determined by 
the District Manager in the interests of safety in the conduct of 
operations and the structural integrity of the drilling unit.
    (d) Foundation requirements. When the lessee fails to provide 
sufficient information pursuant to 30 CFR 550.211 through 550.228 and 
30 CFR 550.241 through 550.262 to support a determination that the 
seafloor is capable of supporting a specific bottom-founded drilling 
unit under the site-specific soil and oceanographic conditions, the 
District Manager may require that additional surveys and soil borings 
be performed and the results submitted for review and evaluation by the 
District Manager before approval is granted for commencing drilling 
operations.
    (e) Tests, surveys, and samples. (1) Lessees shall drill and take 
cores and/or run well and mud logs through the objective interval to 
determine the presence, quality, and quantity of sulphur and other 
minerals (e.g., oil and gas) in the cap rock and the outline of the 
commercial sulphur deposit.
    (2) Inclinational surveys shall be obtained on all vertical wells 
at intervals not exceeding 1,000 feet during the normal course of 
drilling.

[[Page 64578]]

Directional surveys giving both inclination and azimuth shall be 
obtained on all directionally drilled wells at intervals not exceeding 
500 feet during the normal course of drilling and at intervals not 
exceeding 200 feet in all planned angle-change portions of the 
borehole.
    (3) Directional surveys giving both inclination and azimuth shall 
be obtained on both vertically and directionally drilled wells at 
intervals not exceeding 500 feet prior to or upon setting a string of 
casing, or production liner, and at total depth. Composite directional 
surveys shall be prepared with the interval shown from the bottom of 
the conductor casing. In calculating all surveys, a correction from the 
true north to Universal-Transverse-Mercator-Grid-north or Lambert-Grid-
north shall be made after making the magnetic-to-true-north correction. 
A composite dipmeter directional survey or a composite measurement 
while-drilling directional survey will be acceptable as fulfilling the 
applicable requirements of this paragraph.
    (4) Wells are classified as vertical if the calculated average of 
inclination readings weighted by the respective interval lengths 
between readings from surface to drilled depth does not exceed 3 
degrees from the vertical. When the calculated average inclination 
readings weighted by the length of the respective interval between 
readings from the surface to drilled depth exceeds 3 degrees, the well 
is classified as directional.
    (5) At the request of a holder of an adjoining lease, the Regional 
Supervisor may, for the protection of correlative rights, furnish a 
copy of the directional survey to that leaseholder.
    (f) Fixed drilling platforms. Applications for installation of 
fixed drilling platforms or structures including artificial islands 
shall be submitted in accordance with the provisions of subpart I, 
Platforms and Structures, of this part. Mobile drilling units that have 
their jacking equipment removed or have been otherwise immobilized are 
classified as fixed bottom founded drilling platforms.
    (g) Crane operations. You must operate a crane installed on fixed 
platforms according to Sec.  250.108 of this subpart.
    (h) Diesel-engine air intakes. Diesel-engine air intakes must be 
equipped with a device to shut down the diesel engine in the event of 
runaway. Diesel engines that are continuously attended must be equipped 
with either remote-operated manual or automatic-shutdown devices. 
Diesel engines that are not continuously attended must be equipped with 
automatic shutdown devices.

Sec.  250.1606  Control of wells.

    The lessee shall take necessary precautions to keep its wells under 
control at all times. Operations shall be conducted in a safe and 
workmanlike manner. The lessee shall utilize the best available and 
safest drilling technologies and state-of-the-art methods to evaluate 
and minimize the potential for a well to flow or kick. The lessee shall 
utilize personnel who are trained and competent and shall utilize and 
maintain equipment and materials necessary to assure the safety and 
protection of personnel, equipment, natural resources, and the 
environment.

Sec.  250.1607  Field rules.

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

Sec.  250.1608  Well casing and cementing.

    (a) General requirements. (1) For the purpose of this subpart, the 
several casing strings in order of normal installation are:
    (i) Drive or structural,
    (ii) Conductor,
    (iii) Cap rock casing,
    (iv) Bobtail cap rock casing (required when the cap rock casing 
does not penetrate into the cap rock),
    (v) Second cap rock casing (brine wells), and
    (vi) Production liner.
    (2) The lessee shall case and cement all wells with a sufficient 
number of strings of casing cemented in a manner necessary to prevent 
release of fluids from any stratum through the wellbore (directly or 
indirectly) into the sea, protect freshwater aquifers from 
contamination, support unconsolidated sediments, and otherwise provide 
a means of control of the formation pressures and fluids. Cement 
composition, placement techniques, and waiting time shall be designed 
and conducted so that the cement in place behind the bottom 500 feet of 
casing or total length of annular cement fill, if less, attains a 
minimum compressive strength of 160 pounds per square inch (psi).
    (3) The lessee shall install casing designed to withstand the 
anticipated stresses imposed by tensile, compressive, and buckling 
loads; burst and collapse pressures; thermal effects; and combinations 
thereof. Safety factors in the drilling and casing program designs 
shall be of sufficient magnitude to provide well control during 
drilling and to assure safe operations for the life of the well.
    (4) In cases where cement has filled the annular space back to the 
mud line, the cement may be washed out or displaced to a depth not 
exceeding the depth of the structural casing shoe to facilitate casing 
removal upon well abandonment if the District Manager determines that 
subsurface protection against damage to freshwater aquifers and against 
damage caused by adverse loads, pressures, and fluid flows is not 
jeopardized.
    (5) If there are indications of inadequate cementing (such as lost 
returns, cement channeling, or mechanical failure of equipment), the 
lessee shall evaluate the adequacy of the cementing operations by 
pressure testing the casing shoe. If the test indicates inadequate 
cementing, the lessee shall initiate remedial action as approved by the 
District Manager. For cap rock casing, the test for adequacy of 
cementing shall be the pressure testing of the annulus between the cap 
rock and the conductor casings. The pressure shall not exceed 70 
percent of the burst pressure of the conductor casing or 70 percent of 
the collapse pressure of the cap rock casing.
    (b) Drive or structural casing. This casing shall be set by 
driving, jetting, or drilling to a minimum depth of 100 feet below the 
mud line or such other depth, as may be required or approved by the 
District Manager, in order to support unconsolidated deposits and to 
provide hole stability for initial drilling operations. If this portion 
of the hole is drilled, a quantity of cement sufficient to fill the 
annular space back to the mud line shall be used.
    (c) Conductor and cap rock casing setting and cementing 
requirements. (1) Conductor and cap rock casing design and setting 
depths shall be based upon relevant engineering and geologic factors 
including the presence or absence of hydrocarbons, potential hazards, 
and water depths. The proposed casing setting depths may be varied, 
subject to District Manager approval, to permit the casing to be set in 
a competent formation or through

[[Page 64579]]

formations determined desirable to be isolated from the wellbore by 
casing for safer drilling operations. However, the conductor casing 
shall be set immediately prior to drilling into formations known to 
contain oil or gas or, if unknown, upon encountering such formations. 
Cap rock casing shall be set and cemented through formations known to 
contain oil or gas or, if unknown, upon encountering such formations. 
Upon encountering unexpected formation pressures, the lessee shall 
submit a revised casing program to the District Manager for approval.
    (2) Conductor casing shall be cemented with a quantity of cement 
that fills the calculated annular space back to the mud line. Cement 
fill shall be verified by the observation of cement returns. In the 
event that observation of cement returns is not feasible, additional 
quantities of cement shall be used to assure fill to the mud line.
    (3) Cap rock casing shall be cemented with a quantity of cement 
that fills the calculated annular space to at least 200 feet inside the 
conductor casing. When geologic conditions such as near surface 
fractures and faulting exist, cap rock casing shall be cemented with a 
quantity of cement that fills the calculated annular space to the mud 
line, unless otherwise approved by the District Manager. In brine 
wells, the second cap rock casing shall be cemented with a quantity of 
cement that fills the calculated annular space to at least 200 feet 
above the setting depth of the first cap rock casing.
    (d) Bobtail cap rock casing setting and cementing requirements. (1) 
Bobtail cap rock casing shall be set on or just in cap rock and lapped 
a minimum of 100 feet into the previous casing string.
    (2) Sufficient cement shall be used to fill the annular space to 
the top of the bobtail cap rock casing.
    (e) Production liner setting and cementing requirements. (1) 
Production liners for sulphur wells and bleedwells shall be set in cap 
rock at or above the bottom of the open hole (hole that is open in cap 
rock, below the bottom of the cap rock casing) and lapped into the 
previous casing string or to the surface. For brine wells, the liner 
shall be set in salt and lapped into the previous casing string or to 
the surface.
    (2) The production liner is not required to be cemented unless the 
cap rock contains oil or gas. If the cap rock contains oil or gas, 
sufficient cement shall be used to fill the annular space to the top of 
the production liner.

Sec.  250.1609  Pressure testing of casing.

    (a) Prior to drilling the plug after cementing, all casing strings, 
except the drive or structural casing, shall be pressure tested. The 
conductor casing shall be tested to at least 200 psi. All casing 
strings below the conductor casing shall be tested to 500 psi or 0.22 
psi/ft, whichever is greater. (When oil or gas is not present in the 
cap rock, the production liner need not be cemented in place; thus, it 
would not be subject to pressure testing.) If the pressure declines 
more than 10 percent in 30 minutes or if there is another indication of 
a leak, the casing shall be recemented, repaired, or an additional 
casing string run and the casing tested again. The above procedures 
shall be repeated until a satisfactory test is obtained. The time, 
conditions of testing, and results of all casing pressure tests shall 
be recorded in the driller's report.
    (b) After cementing any string of casing other than structural, 
drilling shall not be resumed until there has been a timelapse of at 
least 8 hours under pressure for the conductor casing string or 12 
hours under pressure for all other casing strings. Cement is considered 
under pressure if one or more float valves are shown to be holding the 
cement in place or when other means of holding pressure are used.

Sec.  250.1610  Blowout preventer systems and system components.

    (a) General. The blowout preventer (BOP) systems and system 
components shall be designed, installed, used, maintained, and tested 
to assure well control.
    (b) BOP stacks. The BOP stacks shall consist of an annular 
preventer and the number of ram-type preventers as specified under 
paragraphs (e) and (f) of this section. The pipe rams shall be of 
proper size to fit the drill pipe in use.
    (c) Working pressure. The working-pressure rating of any BOP shall 
exceed the surface pressure to which it may be anticipated to be 
subjected.
    (d) BOP equipment. All BOP systems shall be equipped and provided 
with the following:
    (1) An accumulator system that provides sufficient capacity to 
supply 1.5 times the volume necessary to close and hold closed all BOP 
equipment units with a minimum pressure of 200 psi above the precharge 
pressure, without assistance from a charging system. Accumulator 
regulators supplied by rig air that do not have a secondary source of 
pneumatic supply must be equipped with manual overrides or other 
devices alternately provided to ensure capability of hydraulic 
operations if rig air is lost.
    (2) An automatic backup to the accumulator system. The backup 
system shall be supplied by a power source independent from the power 
source to the primary accumulator system. The automatic backup system 
shall possess sufficient capability to close the BOP and hold it 
closed.
    (3) At least one operable remote BOP control station in addition to 
the one on the drilling floor. This control station shall be in a 
readily accessible location away from the drilling floor.
    (4) A drilling spool with side outlets, if side outlets are not 
provided in the body of the BOP stack, to provide for separate kill and 
choke lines.
    (5) A choke line and a kill line each equipped with two full-
opening valves. At least one of the valves on the choke line and one 
valve on the kill line shall be remotely controlled, except that a 
check valve may be installed on the kill line in lieu of the remotely 
controlled valve, provided that two readily accessible manual valves 
are in place and the check valve is placed between the manual valve and 
the pump.
    (6) A fill-up line above the uppermost preventer.
    (7) A choke manifold designed with consideration of anticipated 
pressures to which it may be subjected, method of well control to be 
employed, surrounding environment, and corrosiveness, volume, and 
abrasiveness of fluids. The choke manifold shall also meet the 
following requirements:
    (i) Manifold and choke equipment subject to well and/or pump 
pressure shall have a rated working pressure at least as great as the 
rated working pressure of the ram-type BOP's or as otherwise approved 
by the District Manager;
    (ii) All components of the choke manifold system shall be protected 
from freezing by heating, draining, or filling with proper fluids; and
    (iii) When buffer tanks are installed downstream of the choke 
assemblies for the purpose of manifolding the bleed lines together, 
isolation valves shall be installed on each line.
    (8) Valves, pipes, flexible steel hoses, and other fittings 
upstream of, and including, the choke manifold with a pressure rating 
at least as great as the rated working pressure of the ram-type BOP's 
unless otherwise approved by the District Manager.
    (9) A wellhead assembly with a rated working pressure that exceeds 
the pressure to which it might be subjected.
    (10) The following system components:

[[Page 64580]]

    (i) A kelly cock (an essentially full-opening valve) installed 
below the swivel and a similar valve of such design that it can be run 
through the BOP stack installed at the bottom of the kelly. A wrench to 
fit each valve shall be stored in a location readily accessible to the 
drilling crew;
    (ii) An inside BOP and an essentially full-opening, drill-string 
safety valve in the open position on the rig floor at all times while 
drilling operations are being conducted. These valves shall be 
maintained on the rig floor to fit all connections that are in the 
drill string. A wrench to fit the drill-string safety valve shall be 
stored in a location readily accessible to the drilling crew;
    (iii) A safety valve available on the rig floor assembled with the 
proper connection to fit the casing string being run in the hole; and
    (iv) Locking devices installed on the ram-type preventers.
    (e) BOP requirements. Prior to drilling below cap rock casing, a 
BOP system shall be installed consisting of at least three remote-
controlled, hydraulically operated BOP's including at least one 
equipped with pipe rams, one with blind rams, and one annular type.
    (f) Tapered drill-string operations. Prior to commencing tapered 
drill-string operations, the BOP stack shall be equipped with 
conventional and/or variable-bore pipe rams to provide either of the 
following:
    (1) One set of variable bore rams capable of sealing around both 
sizes in the string and one set of blind rams, or
    (2) One set of pipe rams capable of sealing around the larger size 
string, provided that blind-shear ram capability is present, and 
crossover subs to the larger size pipe are readily available on the rig 
floor.

Sec.  250.1611  Blowout preventer systems tests, actuations, 
inspections, and maintenance.

    (a) Prior to conducting high-pressure tests, all BOP systems shall 
be tested to a pressure of 200 to 300 psi.
    (b) Ram-type BOP's and the choke manifold shall be pressure tested 
with water to rated working pressure or as otherwise approved by the 
District Manager. Annular type BOP's shall be pressure tested with 
water to 70 percent of rated working pressure or as otherwise approved 
by the District Manager.
    (c) In conjunction with the weekly pressure test of BOP systems 
required in paragraph (d) of this section, the choke manifold valves, 
upper and lower kelly cocks, and drill-string safety valves shall be 
pressure tested to pipe-ram test pressures. Safety valves with proper 
casing connections shall be actuated prior to running casing.
    (d) BOP system shall be pressure tested as follows:
    (1) When installed;
    (2) Before drilling out each string of casing or before continuing 
operations in cases where cement is not drilled out;
    (3) At least once each week, but not exceeding 7 days between 
pressure tests, alternating between control stations. If either control 
system is not functional, further drilling operations shall be 
suspended until that system becomes operable. A period of more than 7 
days between BOP tests is allowed when there is a stuck drill pipe or 
there are pressure control operations and remedial efforts are being 
performed, provided that the pressure tests are conducted as soon as 
possible and before normal operations resume. The date, time, and 
reason for postponing pressure testing shall be entered into the 
driller's report. Pressure testing shall be performed at intervals to 
allow each drilling crew to operate the equipment. The weekly pressure 
test is not required for blind and blind-shear rams;
    (4) Blind and blind-shear rams shall be actuated at least once 
every 7 days. Closing pressure on the blind and blind-shear rams 
greater than necessary to indicate proper operation of the rams is not 
required;
    (5) Variable bore-pipe rams shall be pressure tested against all 
sizes of pipe in use, excluding drill collars and bottomhole tools; and
    (6) Following the disconnection or repair of any well-pressure 
containment seal in the wellhead/BOP stack assembly. In this situation, 
the pressure tests may be limited to the affected component.
    (e) All BOP systems shall be inspected and maintained to assure 
that the equipment will function properly. The BOP systems shall be 
visually inspected at least once each day. The manufacturer's 
recommended inspection and maintenance procedures are acceptable as 
guidelines in complying with this requirement.
    (f) The lessee shall record pressure conditions during BOP tests on 
pressure charts, unless otherwise approved by the District Manager. The 
test duration for each BOP component tested shall be sufficient to 
demonstrate that the component is effectively holding pressure. The 
charts shall be certified as correct by the operator's representative 
at the facility.
    (g) The time, date, and results of all pressure tests, actuations, 
inspections, and crew drills of the BOP system and system components 
shall be recorded in the driller's report. The BOP tests shall be 
documented in accordance with the following:
    (1) The documentation shall indicate the sequential order of BOP 
and auxiliary equipment testing and the pressure and duration of each 
test. As an alternate, the documentation in the driller's report may 
reference a BOP test plan that contains the required information and is 
retained on file at the facility.
    (2) The control station used during the test shall be identified in 
the driller's report.
    (3) Any problems or irregularities observed during BOP and 
auxiliary equipment testing and any actions taken to remedy such 
problems or irregularities shall be noted in the driller's report.
    (4) Documentation required to be entered in the driller's report 
may instead be referenced in the driller's report. All records, 
including pressure charts, driller's report, and referenced documents, 
pertaining to BOP tests, actuations, and inspections, shall be 
available for BSEE review at the facility for the duration of the 
drilling activity. Following completion of the drilling activity, all 
drilling records shall be retained for a period of 2 years at the 
facility, at the lessee's field office nearest the OCS facility, or at 
another location conveniently available to the District Manager.

Sec.  250.1612  Well-control drills.

    Well-control drills shall be conducted for each drilling crew in 
accordance with the requirements set forth in Sec.  250.462 of this 
part or as approved by the District Manager.

Sec.  250.1613  Diverter systems.

    (a) When drilling a conductor or cap rock hole, all drilling units 
shall be equipped with a diverter system consisting of a diverter 
sealing element, diverter lines, and control systems. The diverter 
system shall be designed, installed, and maintained so as to divert 
gases, water, mud, and other materials away from the facilities and 
personnel.
    (b) The diverter system shall be equipped with remote-control 
valves in the flow lines that can be operated from at least one remote-
control station in addition to the one on the drilling floor. Any valve 
used in a diverter system shall be full opening. No manual or butterfly 
valves shall be installed in any part of a diverter system. There shall 
be a minimum number of turns in the vent line(s) downstream of the 
spool outlet flange, and the radius of curvature of turns shall be as 
large as practicable. Flexible hose may be used for diversion

[[Page 64581]]

lines instead of rigid pipe if the flexible hose has integral end 
couplings. The entire diverter system shall be firmly anchored and 
supported to prevent whipping and vibrations. All diverter control 
equipment and lines shall be protected from physical damage from thrown 
and falling objects.
    (c) For drilling operations conducted with a surface wellhead 
configuration, the following shall apply:
    (1) If the diverter system utilizes only one spool outlet, branch 
lines shall be installed to provide downwind diversion capability, and
    (2) No spool outlet or diverter line internal diameter shall be 
less than 10 inches, except that dual spool outlets are acceptable if 
each outlet has a minimum internal diameter of 8 inches, and both 
outlets are piped to overboard lines and that each line downstream of 
the changeover nipple at the spool has a minimum internal diameter of 
10 inches.
    (d) The diverter sealing element and diverter valves shall be 
pressure tested to a minimum of 200 psi when nippled upon conductor 
casing. No more than 7 days shall elapse between subsequent pressure 
tests. The diverter sealing element, diverter valves, and diverter 
control systems (including the remote) shall be actuation tested, and 
the diverter lines shall be tested for flow prior to spudding and 
thereafter at least once each 24-hour period alternating between 
control stations. All test times and results shall be recorded in the 
driller's report.

Sec.  250.1614  Mud program.

    (a) The quantities, characteristics, use, and testing of drilling 
mud and the related drilling procedures shall be designed and 
implemented to prevent the loss of well control.
    (b) The lessee shall comply with requirements concerning mud 
control, mud test and monitoring equipment, mud quantities, and safety 
precautions in enclosed mud handling areas as prescribed in Sec. Sec.  
250.455 through 250.459 of this part, except that the installation of 
an operable degasser in the mud system as required in Sec.  250.456(g) 
is not required for sulphur operations.

Sec.  250.1615  Securing of wells.

    A downhole-safety device such as a cement plug, bridge plug, or 
packer shall be timely installed when drilling operations are 
interrupted by events such as those that force evacuation of the 
drilling crew, prevent station keeping, or require repairs to major 
drilling units or well-control equipment. The use of blind-shear rams 
or pipe rams and an inside BOP may be approved by the District Manager 
in lieu of the above requirements if cap rock casing has been set.

Sec.  250.1616  Supervision, surveillance, and training.

    (a) The lessee shall provide onsite supervision of drilling 
operations at all times.
    (b) From the time drilling operations are initiated and until the 
well is completed or abandoned, a member of the drilling crew or the 
toolpusher shall maintain rig-floor surveillance continuously, unless 
the well is secured with BOP's, bridge plugs, packers, or cement plugs.
    (c) Lessee and drilling contractor personnel shall be trained and 
qualified in accordance with the provisions of subpart O of this part. 
Records of specific training that lessee and drilling contractor 
personnel have successfully completed, the dates of completion, and the 
names and dates of the courses shall be maintained at the drill site.

Sec.  250.1617  Application for permit to drill.

    (a) Before drilling a well under a BOEM-approved Exploration Plan, 
Development and Production Plan, or Development Operations Coordination 
Document, you must file Form BSEE-0123, APD, with the District Manager 
for approval. The submission of your APD must be accompanied by payment 
of the service fee listed in Sec.  250.125. Before starting operations, 
you must receive written approval from the District Manager unless you 
received oral approval under Sec.  250.140.
    (b) An APD shall include rated capacities of the proposed drilling 
unit and of major drilling equipment. After a drilling unit has been 
approved for use in a BSEE district, the information need not be 
resubmitted unless required by the District Manager or there are 
changes in the equipment that affect the rated capacity of the unit.
    (c) An APD shall include a fully completed Form BSEE-0123 and the 
following:
    (1) A plat, drawn to a scale of 2,000 feet to the inch, showing the 
surface and subsurface location of the well to be drilled and of all 
the wells previously drilled in the vicinity from which information is 
available. For development wells on a lease, the wells previously 
drilled in the vicinity need not be shown on the plat. Locations shall 
be indicated in feet from the nearest block line;
    (2) The design criteria considered for the well and for well 
control, including the following:
    (i) Pore pressure;
    (ii) Formation fracture gradients;
    (iii) Potential lost circulation zones;
    (iv) Mud weights;
    (v) Casing setting depths;
    (vi) Anticipated surface pressures (which for purposes of this 
section are defined as the pressure that can reasonably be expected to 
be exerted upon a casing string and its related wellhead equipment). In 
the calculation of anticipated surface pressure, the lessee shall take 
into account the drilling, completion, and producing conditions. The 
lessee shall consider mud densities to be used below various casing 
strings, fracture gradients of the exposed formations, casing setting 
depths, and cementing intervals, total well depth, formation fluid 
type, and other pertinent conditions. Considerations for calculating 
anticipated surface pressure may vary for each segment of the well. The 
lessee shall include as a part of the statement of anticipated surface 
pressure the calculations used to determine this pressure during the 
drilling phase and the completion phase, including the anticipated 
surface pressure used for production string design; and
    (vii) If a shallow hazards site survey is conducted, the lessee 
shall submit with or prior to the submittal of the APD, two copies of a 
summary report describing the geological and manmade conditions 
present. The lessee shall also submit two copies of the site maps and 
data records identified in the survey strategy.
    (3) A BOP equipment program including the following:
    (i) The pressure rating of BOP equipment,
    (ii) A schematic drawing of the diverter system to be used (plan 
and elevation views) showing spool outlet internal diameter(s); 
diverter line lengths and diameters, burst strengths, and radius of 
curvature at each turn; valve type, size, working-pressure rating, and 
location; the control instrumentation logic; and the operating 
procedure to be used by personnel, and
    (iii) A schematic drawing of the BOP stack showing the inside 
diameter of the BOP stack and the number of annular, pipe ram, 
variable-bore pipe ram, blind ram, and blind-shear ram preventers.
    (4) A casing program including the following:
    (i) Casing size, weight, grade, type of connection and setting 
depth, and
    (ii) Casing design safety factors for tension, collapse, and burst 
with the assumptions made to arrive at these values.
    (5) The drilling prognosis including the following:
    (i) Estimated coring intervals,

[[Page 64582]]

    (ii) Estimated depths to the top of significant marker formations, 
and
    (iii) Estimated depths at which encounters with fresh water, 
sulphur, oil, gas, or abnormally pressured water are expected.
    (6) A cementing program including type and amount of cement in 
cubic feet to be used for each casing string;
    (7) A mud program including the minimum quantities of mud and mud 
materials, including weight materials, to be kept at the site;
    (8) A directional survey program for directionally drilled wells;
    (9) An H2S Contingency Plan, if applicable, and if not 
previously submitted; and
    (10) Such other information as may be required by the District 
Manager.
    (d) Public information copies of the APD shall be submitted in 
accordance with Sec.  250.186 of this part.

Sec.  250.1618  Application for permit to modify.

    (a) You must submit requests for changes in plans, changes in major 
drilling equipment, proposals to deepen, sidetrack, complete, workover, 
or plug back a well, or engage in similar activities to the District 
Manager on Form BSEE-0124, Application for Permit to Modify (APM). The 
submission of your APM must be accompanied by payment of the service 
fee listed in Sec.  250.125. Before starting operations associated with 
the change, you must receive written approval from the District Manager 
unless you received oral approval under Sec.  250.140.
    (b) The Form BSEE-0124 submittal shall contain a detailed statement 
of the proposed work that will materially change from the work 
described in the approved APD. Information submitted shall include the 
present state of the well, including the production liner and last 
string of casing, the well depth and production zone, and the well's 
capability to produce. Within 30 days after completion of the work, a 
subsequent detailed report of all the work done and the results 
obtained shall be submitted.
    (c) Public information copies of Form BSEE-0124 shall be submitted 
in accordance with Sec.  250.186 of this part.

Sec.  250.1619  Well records.

    (a) Complete and accurate records for each well and all well 
operations shall be retained for a period of 2 years at the lessee's 
field office nearest the OCS facility or at another location 
conveniently available to the District Manager. The records shall 
contain a description of any significant malfunction or problem; all 
the formations penetrated; the content and character of sulphur in each 
formation if cored and analyzed; the kind, weight, size, grade, and 
setting depth of casing; all well logs and surveys run in the wellbore; 
and all other information required by the District Manager in the 
interests of resource evaluation, prevention of waste, conservation of 
natural resources, protection of correlative rights, safety of 
operations, and environmental protection.
    (b) When drilling operations are suspended or temporarily 
prohibited under the provisions of Sec.  250.170 of this part, the 
lessee shall, within 30 days after termination of the suspension or 
temporary prohibition or within 30 days after the completion of any 
activities related to the suspension or prohibition, transmit to the 
District Manager duplicate copies of the records of all activities 
related to and conducted during the suspension or temporary prohibition 
on, or attached to, Form BSEE-0125, End of Operations Report, or Form 
BSEE-0124, Application for Permit to Modify, as appropriate.
    (c) Upon request by the District Manager or Regional Supervisor, 
the lessee shall furnish the following:
    (1) Copies of the records of any of the well operations specified 
in paragraph (a) of this section;
    (2) Copies of the driller's report at a frequency as determined by 
the District Manager. Items to be reported include spud dates, casing 
setting depths, cement quantities, casing characteristics, mud weights, 
lost returns, and any unusual activities; and
    (3) Legible, exact copies of reports on cementing, acidizing, 
analyses of cores, testing, or other similar services.
    (d) As soon as available, the lessee shall transmit copies of logs 
and charts developed by well-logging operations, directional-well 
surveys, and core analyses. Composite logs of multiple runs and 
directional-well surveys shall be transmitted to the District Manager 
in duplicate as soon as available but not later than 30 days after 
completion of such operations for each well.
    (e) If the District Manager determines that circumstances warrant, 
the lessee shall submit any other reports and records of operations in 
the manner and form prescribed by the District Manager.

Sec.  250.1620  Well-completion and well-workover requirements.

    (a) Lessees shall conduct well-completion and well-workover 
operations in sulphur wells, bleedwells, and brine wells in accordance 
with Sec. Sec.  250.1620 through 250.1626 of this part and other 
provisions of this part as appropriate (see Sec. Sec.  250.501 and 
250.601 of this part for the definition of well-completion and well-
workover operations).
    (b) Well-completion and well-workover operations shall be conducted 
in a manner to protect against harm or damage to life (including fish 
and other aquatic life), property, natural resources of the OCS 
including any mineral deposits (in areas leased and not leased), the 
National security or defense, or the marine, coastal, or human 
environment.

Sec.  250.1621  Crew instructions.

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

Sec.  250.1622  Approvals and reporting of well-completion and well-
workover operations.

    (a) No well-completion or well-workover operation shall begin until 
the lessee receives written approval from the District Manager. 
Approval for such operations shall be requested on Form BSEE-0124. 
Approvals by the District Manager shall be based upon a determination 
that the operations will be conducted in a manner to protect against 
harm or damage to life, property, natural resources of the OCS, 
including any mineral deposits, the National security or defense, or 
the marine, coastal, or human environment.
    (b) The following information shall be submitted with Form BSEE-
0124 (or with Form BSEE-0123):
    (1) A brief description of the well-completion or well-workover 
procedures to be followed;
    (2) When changes in existing subsurface equipment are proposed, a 
schematic drawing showing the well equipment; and
    (3) Where the well is in zones known to contain H2S or 
zones where the presence of H2S is unknown, a description of 
the safety precautions to be implemented.
    (c)(1) Within 30 days after completion, Form BSEE-0125, including a 
schematic of the tubing and the results of any well tests, shall be 
submitted to the District Manager.
    (2) Within 30 days after completing the well-workover operation, 
except routine operations, Form BSEE-0124 shall be submitted to the 
District Manager and shall include the results of any well tests and a 
new schematic of

[[Page 64583]]

the well if any subsurface equipment has been changed.

Sec.  250.1623  Well-control fluids, equipment, and operations.

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

Sec.  250.1624  Blowout prevention equipment.

    (a) The BOP system and system components and related well-control 
equipment shall be designed, used, maintained, and tested in a manner 
necessary to assure well control in foreseeable conditions and 
circumstances, including subfreezing conditions. The working pressure 
of the BOP system and system components shall equal or exceed the 
expected surface pressure to which they may be subjected.
    (b) The minimum BOP stack for well-completion operations or for 
well-workover operations with the tree removed shall consist of the 
following:
    (1) Three remote-controlled, hydraulically operated preventers 
including at least one equipped with pipe rams, one with blind rams, 
and one annular type.
    (2) When a tapered string is used, the minimum BOP stack shall 
consist of either of the following:
    (i) An annular preventer, one set of variable bore rams capable of 
sealing around both sizes in the string, and one set of blind rams; or
    (ii) An annular preventer, one set of pipe rams capable of sealing 
around the larger size string, a preventer equipped with blind-shear 
rams, and a crossover sub to the larger size pipe that shall be readily 
available on the rig floor.
    (c) The BOP systems for well-completion operations, or for well-
workover operations with the tree removed, shall be equipped with the 
following:
    (1) An accumulator system that provides sufficient capacity to 
supply 1.5 times the volume necessary to close and hold closed all BOP 
equipment units with a minimum pressure of 200 psi above the precharge 
pressure without assistance from a charging system. After February 14, 
1992, accumulator regulators supplied by rig air which do not have a 
secondary source of pneumatic supply shall be equipped with manual 
overrides or alternately other devices provided to ensure capability of 
hydraulic operations if rig air is lost;
    (2) An automatic backup to the accumulator system supplied by a 
power source independent from the power source to the primary 
accumulator system and possessing sufficient capacity to close all 
BOP's and hold them closed;
    (3) Locking devices for the pipe-ram preventers;
    (4) At least one remote BOP-control station and one BOP-control 
station on the rig floor; and
    (5) A choke line and a kill line each equipped with two full-
opening valves and a choke manifold. One of the choke-line valves and 
one of the kill-line valves shall be remotely controlled except that a 
check valve may be installed on the kill line in lieu of the remotely-
controlled valve provided that two readily accessible manual valves are 
in place, and the check valve is placed between the manual valve and 
the pump.
    (d) The minimum BOP-stack components for well-workover operations 
with the tree in place and performed through the wellhead inside of the 
sulphur line using small diameter jointed pipe (usually \3/4\ inch to 
1\1/4\ inch) as a work string; i.e., small-tubing operations, shall 
consist of the following:
    (1) For air line changes, the well shall be killed prior to 
beginning operations. The procedures for killing the well shall be 
included in the description of well-workover procedures in accordance 
with Sec.  250.1622 of this part. Under these circumstances, no BOP 
equipment is required.
    (2) For other work inside of the sulphur line, a tubing stripper or 
annular preventer shall be installed prior to beginning work.
    (e) An essentially full-opening, work-string safety valve shall be 
maintained on the rig floor at all times during well-completion 
operations. A wrench to fit the work-string safety valve shall be 
readily available. Proper connections shall be readily available for 
inserting a safety valve in the work string.

Sec.  250.1625  Blowout preventer system testing, records, and drills.

    (a) Prior to conducting high-pressure tests, all BOP systems shall 
be tested to a pressure of 200 to 300 psi.
    (b) Ram-type BOP's and the choke manifold shall be pressure tested 
with water to a rated working pressure or as otherwise approved by the 
District Manager. Annular type BOP's shall be pressure tested with 
water to 70 percent of rated working pressure or as otherwise approved 
by the District Manager.
    (c) In conjunction with the weekly pressure test of BOP systems 
required in paragraph (d) of this section, the choke manifold valves, 
upper and lower kelly cocks, and drill-string safety valves shall be 
pressure tested to pipe-ram test pressures. Safety valves with proper 
casing connections shall be actuated prior to running casing.
    (d) BOP system shall be pressure tested as follows:
    (1) When installed;
    (2) Before drilling out each string of casing or before continuing 
operations in cases where cement is not drilled out;
    (3) At least once each week, but not exceeding 7 days between 
pressure tests, alternating between control stations. If either control 
system is not functional, further drilling operations shall be 
suspended until that system becomes operable. A period of more than 7 
days between BOP tests is allowed when there is a stuck drill pipe or 
there are pressure control operations, and remedial efforts are being 
performed, provided that the pressure tests are conducted as soon as 
possible and before normal operations resume. The time, date, and 
reason for postponing pressure testing shall be entered into the 
driller's report. Pressure testing shall be performed at intervals to 
allow each drilling crew to operate the

[[Page 64584]]

equipment. The weekly pressure test is not required for blind and 
blind-shear rams;
    (4) Blind and blind-shear rams shall be actuated at least once 
every 7 days. Closing pressure on the blind and blind-shear rams 
greater than necessary to indicate proper operation of the rams is not 
required;
    (5) Variable bore-pipe rams shall be pressure tested against all 
sizes of pipe in use, excluding drill collars and bottomhole tools; and
    (6) Following the disconnection or repair of any well-pressure 
containment seal in the wellhead/BOP stack assembly, the pressure tests 
may be limited to the affected component.
    (e) All personnel engaged in well-completion operations shall 
participate in a weekly BOP drill to familiarize crew members with 
appropriate safety measures.
    (f) The lessee shall record pressure conditions during BOP tests on 
pressure charts, unless otherwise approved by the District Manager. The 
test duration for each BOP component tested shall be sufficient to 
demonstrate that the component is effectively holding pressure. The 
charts shall be certified as correct by the operator's representative 
at the facility.
    (g) The time, date, and results of all pressure tests, actuations, 
inspections, and crew drills of the BOP system and system components 
shall be recorded in the operations log. The BOP tests shall be 
documented in accordance with the following:
    (1) The documentation shall indicate the sequential order of BOP 
and auxiliary equipment testing and the pressure and duration of each 
test. As an alternate, the documentation in the operations log may 
reference a BOP test plan that contains the required information and is 
retained on file at the facility.
    (2) The control station used during the test shall be identified in 
the operations log.
    (3) Any problems or irregularities observed during BOP and 
auxiliary equipment testing and any actions taken to remedy such 
problems or irregularities shall be noted in the operations log.
    (4) Documentation required to be entered in the driller's report 
may instead be referenced in the driller's report. All records, 
including pressure charts, driller's report, and referenced documents, 
pertaining to BOP tests, actuations, and inspections shall be available 
for BSEE review at the facility for the duration of the drilling 
activity. Following completion of the drilling activity, all drilling 
records shall be retained for a period of 2 years at the facility, at 
the lessee's field office nearest the OCS facility, or at another 
location conveniently available to the District Manager.

Sec.  250.1626  Tubing and wellhead equipment.

    (a) No tubing string shall be placed into service or continue to be 
used unless such tubing string has the necessary strength and pressure 
integrity and is otherwise suitable for its intended use.
    (b) Wellhead, tree, and related equipment shall be designed, 
installed, tested, used, and maintained so as to achieve and maintain 
pressure control.

Sec.  250.1627  Production requirements.

    (a) The lessee shall conduct sulphur production operations in 
compliance with the approved Development and Production Plan 
requirements of Sec. Sec.  250.1627 through 250.1634 of this subpart 
and requirements of this part, as appropriate.
    (b) Production safety equipment shall be designed, installed, used, 
maintained, and tested in a manner to assure the safety of operations 
and protection of the human, marine, and coastal environments.

Sec.  250.1628  Design, installation, and operation of production 
systems.

    (a) General. All production facilities shall be designed, 
installed, and maintained in a manner that provides for efficiency and 
safety of operations and protection of the environment.
    (b) Approval of design and installation features for sulphur 
production facilities. Prior to installation, the lessee shall submit a 
sulphur production system application, in duplicate, to the District 
Manager for approval. The application shall include information 
relative to the proposed design and installation features. Information 
concerning approved design and installation features shall be 
maintained by the lessee at the lessee's offshore field office nearest 
the OCS facility or at another location conveniently available to the 
District Manager. All approvals are subject to field verification. The 
application shall include the following:
    (1) A schematic flow diagram showing size, capacity, design, 
working pressure of separators, storage tanks, compressor pumps, 
metering devices, and other sulphur-handling vessels;
    (2) A schematic piping diagram showing the size and maximum 
allowable working pressures as determined in accordance with API RP 
14E, Recommended Practice for Design and Installation of Offshore 
Production Platform Piping Systems (as incorporated by reference in 
Sec.  250.198);
    (3) Electrical system information including a plan of each platform 
deck, outlining all hazardous areas classified according to API RP 500, 
Recommended Practice for Classification of Locations for Electrical 
Installations at Petroleum Facilities Classified as Class I, Division 1 
and Division 2, or API RP 505, Recommended Practice for Classification 
of Locations for Electrical Installations at Petroleum Facilities 
Classified as Class I, Zone 0, Zone 1, and Zone 2 (as incorporated by 
reference in Sec.  250.198), and outlining areas in which potential 
ignition sources are to be installed;
    (4) Certification that the design for the mechanical and electrical 
systems to be installed were approved by registered professional 
engineers. After these systems are installed, the lessee shall submit a 
statement to the District Manager certifying that the new installations 
conform to the approved designs of this subpart.
    (c) Hydrocarbon handling vessels associated with fuel gas system. 
You must protect hydrocarbon handling vessels associated with the fuel 
gas system with a basic and ancillary surface safety system. This 
system must be designed, analyzed, installed, tested, and maintained in 
operating condition in accordance with API RP 14C, Analysis, Design, 
Installation, and Testing of Basic Surface Safety Systems for Offshore 
Production Platforms (as incorporated by reference in Sec.  250.198). 
If processing components are to be utilized, other than those for which 
Safety Analysis Checklists are included in API RP 14C, you must use the 
analysis technique and documentation specified therein to determine the 
effect and requirements of these components upon the safety system.
    (d) Approval of safety-systems design and installation features for 
fuel gas system. Prior to installation, the lessee shall submit a fuel 
gas safety system application, in duplicate, to the District Manager 
for approval. The application shall include information relative to the 
proposed design and installation features. Information concerning 
approved design and installation features shall be maintained by the 
lessee at the lessee's offshore field office nearest the OCS facility 
or at another location conveniently available to the District Manager. 
All approvals are subject to field verification. The application shall 
include the following:
    (1) A schematic flow diagram showing size, capacity, design, 
working pressure of separators, storage tanks, compressor

[[Page 64585]]

pumps, metering devices, and other hydrocarbon-handling vessels;
    (2) A schematic flow diagram (API RP 14C, Figure E1, as 
incorporated by reference in Sec.  250.198) and the related Safety 
Analysis Function Evaluation chart (API RP 14C, subsection 4.3c, as 
incorporated by reference in Sec.  250.198).
    (3) A schematic piping diagram showing the size and maximum 
allowable working pressures as determined in accordance with API RP 
14E, Design and Installation of Offshore Production Platform Piping 
Systems (as incorporated by reference in Sec.  250.198);
    (4) Electrical system information including the following:
    (i) A plan of each platform deck, outlining all hazardous areas 
classified according to API RP 500, Recommended Practice for 
Classification of Locations for Electrical Installations at Petroleum 
Facilities Classified as Class I, Division 1 and Division 2, or API RP 
505, Recommended Practice for Classification of Locations for 
Electrical Installations at Petroleum Facilities Classified as Class I, 
Zone 0, Zone 1, and Zone 2 (as incorporated by reference in Sec.  
250.198), and outlining areas in which potential ignition sources are 
to be installed;
    (ii) All significant hydrocarbon sources and a description of the 
type of decking, ceiling, walls (e.g., grating or solid), and 
firewalls; and
    (iii) Elementary electrical schematic of any platform safety 
shutdown system with a functional legend.
    (5) Certification that the design for the mechanical and electrical 
systems to be installed was approved by registered professional 
engineers. After these systems are installed, the lessee shall submit a 
statement to the District Manager certifying that the new installations 
conform to the approved designs of this subpart; and
    (6) Design and schematics of the installation and maintenance of 
all fire- and gas-detection systems including the following:
    (i) Type, location, and number of detection heads;
    (ii) Type and kind of alarm, including emergency equipment to be 
activated;
    (iii) Method used for detection;
    (iv) Method and frequency of calibration; and
    (v) A functional block diagram of the detection system, including 
the electric power supply.

Sec.  250.1629  Additional production and fuel gas system requirements.

    (a) General. Lessees shall comply with the following production 
safety system requirements (some of which are in addition to those 
contained in Sec.  250.1628 of this part).
    (b) Design, installation, and operation of additional production 
systems, including fuel gas handling safety systems. (1) Pressure and 
fired vessels must be designed, fabricated, and code stamped in 
accordance with the applicable provisions of sections I, IV, and VIII 
of the American Society of Mechanical Engineers (ASME) Boiler and 
Pressure Vessel Code (as specified in Sec.  250.198). Pressure and 
fired vessels must have maintenance inspection, rating, repair, and 
alteration performed in accordance with the applicable provisions of 
API Pressure Vessel Inspections Code: In-Service Inspection, Rating, 
Repair, and Alteration, API 510 (except Sections 5.8 and 9.5) (as 
incorporated by reference in Sec.  250.198).
    (i) Pressure safety relief valves shall be designed, installed, and 
maintained in accordance with applicable provisions of sections I, IV, 
and VIII of the ANSI/ASME Boiler and Pressure Vessel Code (as specified 
in Sec.  250.198). The safety relief valves shall conform to the valve-
sizing and pressure-relieving requirements specified in these 
documents; however, the safety relief valves shall be set no higher 
than the maximum-allowable working pressure of the vessel. All safety 
relief valves and vents shall be piped in such a way as to prevent 
fluid from striking personnel or ignition sources.
    (ii) The lessee shall use pressure recorders to establish the 
operating pressure ranges of pressure vessels in order to establish the 
pressure-sensor settings. Pressure-recording charts used to determine 
operating pressure ranges shall be maintained by the lessee for a 
period of 2 years at the lessee's field office nearest the OCS facility 
or at another location conveniently available to the District Manager. 
The high-pressure sensor shall be set no higher than 15 percent or 5 
psi, whichever is greater, above the highest operating pressure of the 
vessel. This setting shall also be set sufficiently below (15 percent 
or 5 psi, whichever is greater) the safety relief valve's set pressure 
to assure that the high-pressure sensor sounds an alarm before the 
safety relief valve starts relieving. The low-pressure sensor shall 
sound an alarm no lower than 15 percent or 5 psi, whichever is greater, 
below the lowest pressure in the operating range.
    (2) Engine exhaust. You must equip engine exhausts to comply with 
the insulation and personnel protection requirements of API RP 14C, 
section 4.2c(4) (as incorporated by reference in Sec.  250.198). 
Exhaust piping from diesel engines must be equipped with spark 
arresters.
    (3) Firefighting systems. Firefighting systems must conform to 
subsection 5.2, Fire Water Systems, of API RP 14G, Recommended Practice 
for Fire Prevention and Control on Open Type Offshore Production 
Platforms (as incorporated by reference in Sec.  250.198), and must be 
subject to the approval of the District Manager. Additional 
requirements must apply as follows:
    (i) A firewater system consisting of rigid pipe with firehose 
stations shall be installed. The firewater system shall be installed to 
provide needed protection, especially in areas where fuel handling 
equipment is located.
    (ii) Fuel or power for firewater pump drivers shall be available 
for at least 30 minutes of run time during platform shut-in time. If 
necessary, an alternate fuel or power supply shall be installed to 
provide for this pump-operating time unless an alternate firefighting 
system has been approved by the District Manager;
    (iii) A firefighting system using chemicals may be used in lieu of 
a water system if the District Manager determines that the use of a 
chemical system provides equivalent fire-protection control; and
    (iv) A diagram of the firefighting system showing the location of 
all firefighting equipment shall be posted in a prominent place on the 
facility or structure.
    (4) Fire- and gas-detection system. (i) Fire (flame, heat, or 
smoke) sensors shall be installed in all enclosed classified areas. Gas 
sensors shall be installed in all inadequately ventilated, enclosed 
classified areas. Adequate ventilation is defined as ventilation that 
is sufficient to prevent accumulation of significant quantities of 
vapor-air mixture in concentrations over 25 percent of the lower 
explosive limit. One approved method of providing adequate ventilation 
is a change of air volume each 5 minutes or 1 cubic foot of air-volume 
flow per minute per square foot of solid floor area, whichever is 
greater. Enclosed areas (e.g., buildings, living quarters, or 
doghouses) are defined as those areas confined on more than four of 
their six possible sides by walls, floors, or ceilings more restrictive 
to air flow than grating or fixed open louvers and of sufficient size 
to allow entry of personnel. A classified area is any area classified 
Class I, Group D, Division 1 or 2, following the guidelines of API RP 
500 (as incorporated by reference in Sec.  250.198), or any area 
classified Class I, Zone 0, Zone 1, or Zone 2, following the guidelines 
of API RP 505 (as incorporated by reference in Sec.  205.198).

[[Page 64586]]

    (ii) All detection systems shall be capable of continuous 
monitoring. Fire-detection systems and portions of combustible gas-
detection systems related to the higher gas concentration levels shall 
be of the manual-reset type. Combustible gas-detection systems related 
to the lower gas-concentration level may be of the automatic-reset 
type.
    (iii) A fuel-gas odorant or an automatic gas-detection and alarm 
system is required in enclosed, continuously manned areas of the 
facility that are provided with fuel gas. Living quarters and doghouses 
not containing a gas source and not located in a classified area do not 
require a gas detection system.
    (iv) The District Manager may require the installation and 
maintenance of a gas detector or alarm in any potentially hazardous 
area.
    (v) Fire- and gas-detection systems must be an approved type, 
designed and installed according to API RP 14C, API RP 14G, and either 
API RP 14F or API RP 14FZ (the preceding four documents as incorporated 
by reference in Sec.  250.198).
    (c) General platform operations. Safety devices shall not be 
bypassed or blocked out of service unless they are temporarily out of 
service for startup, maintenance, or testing procedures. Only the 
minimum number of safety devices shall be taken out of service. 
Personnel shall monitor the bypassed or blocked out functions until the 
safety devices are placed back in service. Any safety device that is 
temporarily out of service shall be flagged by the person taking such 
device out of service.

Sec.  250.1630  Safety-system testing and records.

    (a) Inspection and testing. You must inspect and successfully test 
safety system devices at the interval specified below or more 
frequently if operating conditions warrant. Testing must be in 
accordance with API RP 14C, Appendix D (as incorporated by reference in 
Sec.  250.198). For safety system devices other than those listed in 
API RP 14C, Appendix D, you must utilize the analysis technique and 
documentation specified therein for inspection and testing of these 
components, and the following:
    (1) Safety relief valves on the natural gas feed system for power 
plant operations such as pressure safety valves shall be inspected and 
tested for operation at least once every 12 months. These valves shall 
be either bench tested or equipped to permit testing with an external 
pressure source.
    (2) The following safety devices (excluding electronic pressure 
transmitters and level sensors) must be inspected and tested at least 
once each calendar month, but at no time may more than 6 weeks elapse 
between tests:
    (i) All pressure safety high or pressure safety low, and
    (ii) All level safety high and level safety low controls.
    (3) The following electronic pressure transmitters and level 
sensors must be inspected and tested at least once every 3 months, but 
at no time may more than 120 days elapse between tests:
    (i) All PSH or PSL, and
    (ii) All LSH and LSL controls.
    (4) All pumps for firewater systems shall be inspected and operated 
weekly.
    (5) All fire- (flame, heat, or smoke) and gas-detection systems 
shall be inspected and tested for operation and recalibrated every 3 
months provided that testing can be performed in a nondestructive 
manner.
    (6) Prior to the commencement of production, the lessee shall 
notify the District Manager when the lessee is ready to conduct a 
preproduction test and inspection of the safety system. The lessee 
shall also notify the District Manager upon commencement of production 
in order that a complete inspection may be conducted.
    (b) Records. The lessee shall maintain records for a period of 2 
years for each safety device installed. These records shall be 
maintained by the lessee at the lessee's field office nearest the OCS 
facility or another location conveniently available to the District 
Manager. These records shall be available for BSEE review. The records 
shall show the present status and history of each safety device, 
including dates and details of installation, removal, inspection, 
testing, repairing, adjustments, and reinstallation.

Sec.  250.1631  Safety device training.

    Prior to engaging in production operations on a lease and 
periodically thereafter, personnel installing, inspecting, testing, and 
maintaining safety devices shall be instructed in the safety 
requirements of the operations to be performed; possible hazards to be 
encountered; and general safety considerations to be taken to protect 
personnel, equipment, and the environment. Date and time of safety 
meetings shall be recorded and available for BSEE review.

Sec.  250.1632  Production rates.

    Each sulphur deposit shall be produced at rates that will provide 
economic development and depletion of the deposit in a manner that 
would maximize the ultimate recovery of sulphur without resulting in 
waste (e.g., an undue reduction in the recovery of oil and gas from an 
associated hydrocarbon accumulation).

Sec.  250.1633  Production measurement.

    (a) General. Measurement equipment and security procedures shall be 
designed, installed, used, maintained, and tested so as to accurately 
and completely measure the sulphur produced on a lease for purposes of 
royalty determination.
    (b) Application and approval. The lessee shall not commence 
production of sulphur until the Regional Supervisor has approved the 
method of measurement. The request for approval of the method of 
measurement shall contain sufficient information to demonstrate to the 
satisfaction of the Regional Supervisor that the method of measurement 
meets the requirements of paragraph (a) of this section.

Sec.  250.1634  Site security.

    (a) All locations where sulphur is produced, measured, or stored 
shall be operated and maintained to ensure against the loss or theft of 
produced sulphur and to assure accurate and complete measurement of 
produced sulphur for royalty purposes.
    (b) Evidence of mishandling of produced sulphur from an offshore 
lease, or tampering or falsifying any measurement of production for an 
offshore lease, shall be reported to the Regional Supervisor as soon as 
possible but no later than the next business day after discovery of the 
evidence of mishandling.

Subpart Q--Decommissioning Activities

General

Sec.  250.1700  What do the terms ``decommissioning'', 
``obstructions'', and ``facility'' mean?

    (a) Decommissioning means:
    (1) Ending oil, gas, or sulphur operations; and
    (2) Returning the lease or pipeline right-of-way to a condition 
that meets the requirements of regulations of BSEE and other agencies 
that have jurisdiction over decommissioning activities.
    (b) Obstructions mean structures, equipment, or objects that were 
used in oil, gas, or sulphur operations or marine growth that, if left 
in place, would hinder other users of the OCS. Obstructions may 
include, but are not limited to, shell mounds, wellheads, casing stubs, 
mud line suspensions, well protection devices, subsea trees, jumper 
assemblies, umbilicals, manifolds, termination skids, production and 
pipeline risers,

[[Page 64587]]

platforms, templates, pilings, pipelines, pipeline valves, and power 
cables.
    (c) Facility means any installation other than a pipeline used for 
oil, gas, or sulphur activities that is permanently or temporarily 
attached to the seabed on the OCS. Facilities include production and 
pipeline risers, templates, pilings, and any other facility or 
equipment that constitutes an obstruction such as jumper assemblies, 
termination skids, umbilicals, anchors, and mooring lines.

Sec.  250.1701  Who must meet the decommissioning obligations in this 
subpart?

    (a) Lessees and owners of operating rights are jointly and 
severally responsible for meeting decommissioning obligations for 
facilities on leases, including the obligations related to lease-term 
pipelines, as the obligations accrue and until each obligation is met.
    (b) All holders of a right-of-way are jointly and severally liable 
for meeting decommissioning obligations for facilities on their right-
of-way, including right-of-way pipelines, as the obligations accrue and 
until each obligation is met.
    (c) In this subpart, the terms ``you'' or ``I'' refer to lessees 
and owners of operating rights, as to facilities installed under the 
authority of a lease, and to right-of-way holders as to facilities 
installed under the authority of a right-of-way.

Sec.  250.1702  When do I accrue decommissioning obligations?

    You accrue decommissioning obligations when you do any of the 
following:
    (a) Drill a well;
    (b) Install a platform, pipeline, or other facility;
    (c) Create an obstruction to other users of the OCS;
    (d) Are or become a lessee or the owner of operating rights of a 
lease on which there is a well that has not been permanently plugged 
according to this subpart, a platform, a lease term pipeline, or other 
facility, or an obstruction;
    (e) Are or become the holder of a pipeline right-of-way on which 
there is a pipeline, platform, or other facility, or an obstruction; or
    (f) Re-enter a well that was previously plugged according to this 
subpart.

Sec.  250.1703  What are the general requirements for decommissioning?

    When your facilities are no longer useful for operations, you must:
    (a) Get approval from the appropriate District Manager before 
decommissioning wells and from the Regional Supervisor before 
decommissioning platforms and pipelines or other facilities;
    (b) Permanently plug all wells;
    (c) Remove all platforms and other facilities, except as provided 
in Sec. Sec.  250.1725(a) and 250.1730.
    (d) Decommission all pipelines;
    (e) Clear the seafloor of all obstructions created by your lease 
and pipeline right-of-way operations; and
    (f) Conduct all decommissioning activities in a manner that is 
safe, does not unreasonably interfere with other uses of the OCS, and 
does not cause undue or serious harm or damage to the human, marine, or 
coastal environment.

Sec.  250.1704  When must I submit decommissioning applications and 
reports?

    You must submit decommissioning applications and receive approval 
and submit subsequent reports according to the table in this section.

                                 Decommissioning Applications and Reports Table
----------------------------------------------------------------------------------------------------------------
  Decommissioning applications and
              reports                      When to submit                          Instructions
----------------------------------------------------------------------------------------------------------------
(a) Initial platform removal         In the Pacific OCS Region   Include information required under Sec.
 application [not required in the     or Alaska OCS Region,       250.1726.
 Gulf of Mexico OCS Region].          submit the application to
                                      the Regional Supervisor
                                      at least 2 years before
                                      production is projected
                                      to cease.
(b) Final removal application for a  Before removing a platform  Include information required under Sec.
 platform or other facility.          or other facility in the    250.1727.
                                      Gulf of Mexico OCS
                                      Region, or not more than
                                      2 years after the
                                      submittal of an initial
                                      platform removal
                                      application to the
                                      Pacific OCS Region and
                                      the Alaska OCS Region.
(c) Post-removal report for a        Within 30 days after you    Include information required under Sec.
 platform or other facility.          remove a platform or        250.1729.
                                      other facility.
(d) Pipeline decommissioning         Before you decommission a   Include information required under Sec.
 application.                         pipeline.                   250.1751(a) or Sec.   250.1752(a), as
                                                                  applicable.
(e) Post-pipeline decommissioning    Within 30 days after you    Include information required under Sec.
 report.                              decommission a pipeline.    250.1753.
(f) Site clearance report for a      Within 30 days after you    Include information required under Sec.
 platform or other facility.          complete site clearance     250.1743(b).
                                      verification activities.
(g) Form BSEE-0124, Application for  (1) Before you temporarily  Include information required under Sec.  Sec.
 Permit to Modify (APM). The          abandon or permanently      250.1712 and 250.1721.
 submission of your APM must be       plug a well or zone,
 accompanied by payment of the
 service fee listed in Sec.
 250.125.
                                     (2) Within 30 days after    Include information required under Sec.
                                      you plug a well.            250.1717.
                                     (3) Before you install a    Refer to Sec.   250.1722(a).
                                      subsea protective device.
                                     (4) Within 30 days after    Include information required under Sec.
                                      you complete a protective   250.1722(d).
                                      device trawl test.
                                     (5) Before you remove any   Refer to Sec.   250.1723.
                                      casing stub or mud line
                                      suspension equipment and
                                      any subsea protective
                                      device.
                                     (6) Within 30 days after    Include information required under Sec.
                                      you complete site           250.1743(a).
                                      clearance verification
                                      activities.
----------------------------------------------------------------------------------------------------------------

[[Page 64588]]

Permanently Plugging Wells

Sec.  250.1710  When must I permanently plug all wells on a lease?

    You must permanently plug all wells on a lease within 1 year after 
the lease terminates.

Sec.  250.1711  When will BSEE order me to permanently plug a well?

    BSEE will order you to permanently plug a well if that well:
    (a) Poses a hazard to safety or the environment; or
    (b) Is not useful for lease operations and is not capable of oil, 
gas, or sulphur production in paying quantities.

Sec.  250.1712  What information must I submit before I permanently 
plug a well or zone?

    Before you permanently plug a well or zone, you must submit form 
BSEE-0124, Application for Permit to Modify, to the appropriate 
District Manager and receive approval. A request for approval must 
contain the following information:
    (a) The reason you are plugging the well (or zone), for completions 
with production amounts specified by the Regional Supervisor, along 
with substantiating information demonstrating its lack of capacity for 
further profitable production of oil, gas, or sulfur;
    (b) Recent well test data and pressure data, if available;
    (c) Maximum possible surface pressure, and how it was determined;
    (d) Type and weight of well-control fluid you will use;
    (e) A description of the work;
    (f) A current and proposed well schematic and description that 
includes:
    (1) Well depth;
    (2) All perforated intervals that have not been plugged;
    (3) Casing and tubing depths and details;
    (4) Subsurface equipment;
    (5) Estimated tops of cement (and the basis of the estimate) in 
each casing annulus;
    (6) Plug locations;
    (7) Plug types;
    (8) Plug lengths;
    (9) Properties of mud and cement to be used;
    (10) Perforating and casing cutting plans;
    (11) Plug testing plans;
    (12) Casing removal (including information on explosives, if used);
    (13) Proposed casing removal depth; and
    (14) Your plans to protect archaeological and sensitive biological 
features, including anchor damage during plugging operations, a brief 
assessment of the environmental impacts of the plugging operations, and 
the procedures and mitigation measures you will take to minimize such 
impacts; and
    (g) Certification by a Registered Professional Engineer of the well 
abandonment design and procedures; that there will be at least two 
independent tested barriers, including one mechanical barrier, across 
each flow path during abandonment activities; and that the plug meets 
the requirements in the table in Sec.  250.1715. The Registered 
Professional Engineer must be registered in a State in the United 
States. You must submit this certification with your APM (Form BSEE-
0124).

Sec.  250.1713  Must I notify BSEE before I begin well plugging 
operations?

    You must notify the appropriate District Manager at least 48 hours 
before beginning operations to permanently plug a well.

Sec.  250.1714  What must I accomplish with well plugs?

    You must ensure that all well plugs:
    (a) Provide downhole isolation of hydrocarbon and sulphur zones;
    (b) Protect freshwater aquifers; and
    (c) Prevent migration of formation fluids within the wellbore or to 
the seafloor.

Sec.  250.1715  How must I permanently plug a well?

    (a) You must permanently plug wells according to the table in this 
section. The District Manager may require additional well plugs as 
necessary.

                                      Permanent Well Plugging Requirements
----------------------------------------------------------------------------------------------------------------
                 If you have . . .                                    Then you must use . . .
---------------------------------------------------------------------------------------------------------------
(1) Zones in open hole,                              Cement plug(s) set from at least 100 feet below the
                                                      bottom to 100 feet above the top of oil, gas, and fresh-
                                                      water zones to isolate fluids in the strata.
(2) Open hole below casing,                          (i) A cement plug, set by the displacement method, at
                                                      least 100 feet above and below deepest casing shoe;
                                                     (ii) A cement retainer with effective back-pressure
                                                      control set 50 to 100 feet above the casing shoe, and a
                                                      cement plug that extends at least 100 feet below the
                                                      casing shoe and at least 50 feet above the retainer; or
                                                     (iii) A bridge plug set 50 feet to 100 feet above the
                                                      shoe with 50 feet of cement on top of the bridge plug,
                                                      for expected or known lost circulation conditions.
(3) A perforated zone that is currently open and     (i) A method to squeeze cement to all perforations;
 not previously squeezed or isolated,                (ii) A cement plug set by the displacement method, at
                                                      least 100 feet above to 100 feet below the perforated
                                                      interval, or down to a casing plug, whichever is less;
                                                      or.
                                                     (iii) If the perforated zones are isolated from the hole
                                                      below, you may use any of the plugs specified in
                                                      paragraphs (a)(3)(iii)(A) through (E) of this section
                                                      instead of those specified in paragraphs (a)(3)(i) and
                                                      (a)(3)(ii) of this section..
                                                     (A) A cement retainer with effective back-pressure
                                                      control set 50 to 100 feet above the top of the
                                                      perforated interval, and a cement plug that extends at
                                                      least 100 feet below the bottom of the perforated
                                                      interval with at least 50 feet of cement above the
                                                      retainer;
                                                     (B) A bridge plug set 50 to 100 feet above the top of the
                                                      perforated interval and at least 50 feet of cement on
                                                      top of the bridge plug;
                                                     (C) A cement plug at least 200 feet in length, set by the
                                                      displacement method, with the bottom of the plug no more
                                                      than 100 feet above the perforated interval;
                                                     (D) A through-tubing basket plug set no more than 100
                                                      feet above the perforated interval with at least 50 feet
                                                      of cement on top of the basket plug; or
                                                     (E) A tubing plug set no more than 100 feet above the
                                                      perforated interval topped with a sufficient volume of
                                                      cement so as to extend at least 100 feet above the
                                                      uppermost packer in the wellbore and at least 300 feet
                                                      of cement in the casing annulus immediately above the
                                                      packer.
(4) A casing stub where the stub end is within the   (i) A cement plug set at least 100 feet above and below
 casing,                                              the stub end;

[[Page 64589]]

 
                                                     (ii) A cement retainer or bridge plug set at least 50 to
                                                      100 feet above the stub end with at least 50 feet of
                                                      cement on top of the retainer or bridge plug; or
                                                     (iii) A cement plug at least 200 feet long with the
                                                      bottom of the plug set no more than 100 feet above the
                                                      stub end.
(5) A casing stub where the stub end is below the    A plug as specified in paragraph (a)(1) or (a)(2) of this
 casing,                                              section, as applicable.
(6) An annular space that communicates with open     A cement plug at least 200 feet long set in the annular
 hole and extends to the mud line,                    space. For a well completed above the ocean surface, you
                                                      must pressure test each casing annulus to verify
                                                      isolation.
(7) A subsea well with unsealed annulus,             A cutter to sever the casing, and you must set a stub
                                                      plug as specified in paragraphs (a)(4) and (a)(5) of
                                                      this section.
(8) A well with casing,                              A cement surface plug at least 150 feet long set in the
                                                      smallest casing that extends to the mud line with the
                                                      top of the plug no more than 150 feet below the mud
                                                      line.
(9) Fluid left in the hole,                          A fluid in the intervals between the plugs that is dense
                                                      enough to exert a hydrostatic pressure that is greater
                                                      than the formation pressures in the intervals.
(10) Permafrost areas,                               (i) A fluid to be left in the hole that has a freezing
                                                      point below the temperature of the permafrost, and a
                                                      treatment to inhibit corrosion; and
                                                     (ii) Cement plugs designed to set before freezing and
                                                      have a low heat of hydration.
----------------------------------------------------------------------------------------------------------------

     (b) You must test the first plug below the surface plug and all 
plugs in lost circulation areas that are in open hole. The plug must 
pass one of the following tests to verify plug integrity:
    (1) A pipe weight of at least 15,000 pounds on the plug; or
    (2) A pump pressure of at least 1,000 pounds per square inch. 
Ensure that the pressure does not drop more than 10 percent in 15 
minutes. The District Manager may require you to tests other plug(s).

Sec.  250.1716  To what depth must I remove wellheads and casings?

    (a) Unless the District Manager approves an alternate depth under 
paragraph (b) of this section, you must remove all wellheads and 
casings to at least 15 feet below the mud line.
    (b) The District Manager may approve an alternate removal depth if:
    (1) The wellhead or casing would not become an obstruction to other 
users of the seafloor or area, and geotechnical and other information 
you provide demonstrate that erosional processes capable of exposing 
the obstructions are not expected; or
    (2) You determine, and BSEE concurs, that you must use divers, and 
the seafloor sediment stability poses safety concerns; or
    (3) The water depth is greater than 800 meters (2,624 feet).

Sec.  250.1717  After I permanently plug a well, what information must 
I submit?

    Within 30 days after you permanently plug a well, you must submit 
form BSEE-0124, Application for Permit to Modify (subsequent report), 
to the appropriate District Manager, and include the following 
information:
    (a) Information included in Sec.  250.1712 with a final well 
schematic;
    (b) Description of the plugging work;
    (c) Nature and quantities of material used in the plugs; and
    (d) If you cut and pulled any casing string, the following 
information:
    (1) A description of the methods used (including information on 
explosives, if used);
    (2) Size and amount of casing removed; and
    (3) Casing removal depth.

Temporary Abandoned Wells

Sec.  250.1721  If I temporarily abandon a well that I plan to re-
enter, what must I do?

    You may temporarily abandon a well when it is necessary for proper 
development and production of a lease. To temporarily abandon a well, 
you must do all of the following:
    (a) Submit form BSEE-0124, Application for Permit to Modify, and 
the applicable information required by Sec.  250.1712 to the 
appropriate District Manager and receive approval;
    (b) Adhere to the plugging and testing requirements for permanently 
plugged wells listed in the table in Sec.  250.1715, except for Sec.  
250.1715(a)(8). You do not need to sever the casings, remove the 
wellhead, or clear the site;
    (c) Set a bridge plug or a cement plug at least 100-feet long at 
the base of the deepest casing string, unless the casing string has 
been cemented and has not been drilled out. If a cement plug is set, it 
is not necessary for the cement plug to extend below the casing shoe 
into the open hole;
    (d) Set a retrievable or a permanent-type bridge plug or a cement 
plug at least 100 feet long in the inner-most casing. The top of the 
bridge plug or cement plug must be no more than 1,000 feet below the 
mud line. BSEE may consider approving alternate requirements for subsea 
wells case-by-case;
    (e) Identify and report subsea wellheads, casing stubs, or other 
obstructions that extend above the mud line according to U.S. Coast 
Guard (USCG) requirements;
    (f) Except in water depths greater than 300 feet, protect subsea 
wellheads, casing stubs, mud line suspensions, or other obstructions 
remaining above the seafloor by using one of the following methods, as 
approved by the District Manager or Regional Supervisor:
    (1) A caisson designed according to 30 CFR 250, subpart I, and 
equipped with aids to navigation;
    (2) A jacket designed according to 30 CFR 250, subpart I, and 
equipped with aids to navigation; or
    (3) A subsea protective device that meets the requirements in Sec.  
250.1722.
    (g) Within 30 days after you temporarily plug a well, you must 
submit form BSEE-0124, Application for Permit to Modify (subsequent 
report), and include the following information:
    (1) Information included in Sec.  250.1712 with a well schematic;
    (2) Information required by Sec.  250.1717(b), (c), and (d); and
    (3) A description of any remaining subsea wellheads, casing stubs, 
mudline suspension equipment, or other obstructions that extend above 
the seafloor; and
    (h) Submit certification by a Registered Professional Engineer of 
the well abandonment design and procedures; that there will be at least 
two independent tested barriers, including one mechanical barrier, 
across each flow path during abandonment activities; and that the plug 
meets the requirements in the table in Sec.  250.1715. The Registered 
Professional Engineer must be registered in a State in the United 
States. You must submit this

[[Page 64590]]

certification with your APM (Form BSEE-0124) required by Sec.  
250.1712.

Sec.  250.1722  If I install a subsea protective device, what 
requirements must I meet?

    If you install a subsea protective device under Sec.  
250.1721(f)(3), you must install it in a manner that allows fishing 
gear to pass over the obstruction without damage to the obstruction, 
the protective device, or the fishing gear.
    (a) Use form BSEE-0124, Application for Permit to Modify to request 
approval from the appropriate District Manager to install a subsea 
protective device.
    (b) The protective device may not extend more than 10 feet above 
the seafloor (unless BSEE approves otherwise).
    (c) You must trawl over the protective device when you install it 
(adhere to the requirements at Sec.  250.1741(d) through (h)). If the 
trawl does not pass over the protective device or causes damage to it, 
you must notify the appropriate District Manager within 5 days and 
perform remedial action within 30 days of the trawl;
    (d) Within 30 days after you complete the trawling test described 
in paragraph (c) of this section, submit a report to the appropriate 
District Manager using form BSEE-0124, Application for Permit to Modify 
that includes the following:
    (1) The date(s) the trawling test was performed and the vessel that 
was used;
    (2) A plat at an appropriate scale showing the trawl lines;
    (3) A description of the trawling operation and the net(s) that 
were used;
    (4) An estimate by the trawling contractor of the seafloor 
penetration depth achieved by the trawl;
    (5) A summary of the results of the trawling test including a 
discussion of any snags and interruptions, a description of any damage 
to the protective covering, the casing stub or mud line suspension 
equipment, or the trawl, and a discussion of any snag removals 
requiring diver assistance; and
    (6) A letter signed by your authorized representative stating that 
he/she witnessed the trawling test.
    (e) If a temporarily abandoned well is protected by a subsea device 
installed in a water depth less than 100 feet, mark the site with a 
buoy installed according to the USCG requirements.
    (f) Provide annual reports to the Regional Supervisor describing 
your plans to either re-enter and complete the well or to permanently 
plug the well.
    (g) Ensure that all subsea wellheads, casing stubs, mud line 
suspensions, or other obstructions in water depths less than 300 feet 
remain protected.
    (1) To confirm that the subsea protective covering remains properly 
installed, either conduct a visual inspection or perform a trawl test 
at least annually.
    (2) If the inspection reveals that a casing stub or mud line 
suspension is no longer properly protected, or if the trawl does not 
pass over the subsea protective covering without causing damage to the 
covering, the casing stub or mud line suspension equipment, or the 
trawl, notify the appropriate District Manager within 5 days, and 
perform the necessary remedial work within 30 days of discovery of the 
problem.
    (3) In your annual report required by paragraph (f) of this 
section, include the inspection date, results, and method used and a 
description of any remedial work you will perform or have performed.
    (h) You may request approval to waive the trawling test required by 
paragraph (c) of this section if you plan to use either:
    (1) A buoy with automatic tracking capabilities installed and 
maintained according to USCG requirements at 33 CFR part 67 (or its 
successor); or
    (2) A design and installation method that has been proven 
successful by trawl testing of previous protective devices of the same 
design and installed in areas with similar bottom conditions.

Sec.  250.1723  What must I do when it is no longer necessary to 
maintain a well in temporary abandoned status?

    If you or BSEE determines that continued maintenance of a well in a 
temporary abandoned status is not necessary for the proper development 
or production of a lease, you must:
    (a) Promptly and permanently plug the well according to Sec.  
250.1715;
    (b) Remove any casing stub or mud line suspension equipment and any 
subsea protective covering. You must submit a request for approval to 
perform such work to the appropriate District Manager using form BSEE-
0124, Application for Permit to Modify; and
    (c) Clear the well site according to Sec.  250.1740 through Sec.  
250.1742.

Removing Platforms and Other Facilities

Sec.  250.1725  When do I have to remove platforms and other 
facilities?

    (a) You must remove all platforms and other facilities within 1 
year after the lease or pipeline right-of-way terminates, unless you 
receive approval to maintain the structure to conduct other activities. 
Platforms include production platforms, well jackets, single-well 
caissons, and pipeline accessory platforms. Other activities include 
those supporting OCS oil and gas production and transportation, as well 
as other energy-related or marine-related uses (including LNG) for 
which adequate financial assurance for decommissioning has been 
provided to a Federal agency which has given BSEE a commitment that it 
has and will exercise authority to compel the performance of 
decommissioning within a time following cessation of the new use 
acceptable to BSEE. The approval will specify:
    (1) Whether you must continue to maintain any financial assurance 
for decommissioning; and
    (2) Whether, and under what circumstances, you must perform any 
decommissioning not performed by the new facility owner/user.
    (b) Before you may remove a platform or other facility, you must 
submit a final removal application to the Regional Supervisor for 
approval and include the information listed in Sec.  250.1727.
    (c) You must remove a platform or other facility according to the 
approved application.
    (d) You must flush all production risers with seawater before you 
remove them.
    (e) You must notify the Regional Supervisor at least 48 hours 
before you begin the removal operations.

Sec.  250.1726  When must I submit an initial platform removal 
application and what must it include?

    An initial platform removal application is required only for leases 
and pipeline rights-of-way in the Pacific OCS Region or the Alaska OCS 
Region. It must include the following information:
    (a) Platform or other facility removal procedures, including the 
types of vessels and equipment you will use;
    (b) Facilities (including pipelines) you plan to remove or leave in 
place;
    (c) Platform or other facility transportation and disposal plans;
    (d) Plans to protect marine life and the environment during 
decommissioning operations, including a brief assessment of the 
environmental impacts of the operations, and procedures and mitigation 
measures that you will take to minimize the impacts; and
    (e) A projected decommissioning schedule.

Sec.  250.1727  What information must I include in my final application 
to remove a platform or other facility?

    You must submit to the Regional Supervisor, a final application for 
approval to remove a platform or other facility. Your application must 
be accompanied by payment of the service fee listed in Sec.  250.125. 
If you are

[[Page 64591]]

proposing to use explosives, provide three copies of the application. 
If you are not proposing to use explosives, provide two copies of the 
application. Include the following information in the final removal 
application, as applicable:
    (a) Identification of the applicant including:
    (1) Lease operator/pipeline right-of-way holder;
    (2) Address;
    (3) Contact person and telephone number; and
    (4) Shore base.
    (b) Identification of the structure you are removing including:
    (1) Platform Name/BSEE Complex ID Number;
    (2) Location (lease/right-of-way, area, block, and block 
coordinates);
    (3) Date installed (year);
    (4) Proposed date of removal (Month/Year); and
    (5) Water depth.
    (c) Description of the structure you are removing including:
    (1) Configuration (attach a photograph or a diagram);
    (2) Size;
    (3) Number of legs/casings/pilings;
    (4) Diameter and wall thickness of legs/casings/pilings;
    (5) Whether piles are grouted inside or outside;
    (6) Brief description of soil composition and condition;
    (7) The sizes and weights of the jacket, topsides (by module), 
conductors, and pilings; and
    (8) The maximum removal lift weight and estimated number of main 
lifts to remove the structure.
    (d) A description, including anchor pattern, of the vessel(s) you 
will use to remove the structure.
    (e) Identification of the purpose, including:
    (1) Lease expiration/right-of-way relinquishment date; and
    (2) Reason for removing the structure.
    (f) A description of the removal method, including:
    (1) A brief description of the method you will use;
    (2) If you are using explosives, the following:
    (i) Type of explosives;
    (ii) Number and sizes of charges;
    (iii) Whether you are using single shot or multiple shots;
    (iv) If multiple shots, the sequence and timing of detonations;
    (v) Whether you are using a bulk or shaped charge;
    (vi) Depth of detonation below the mud line; and
    (vii) Whether you are placing the explosives inside or outside of 
the pilings;
    (3) If you will use divers or acoustic devices to conduct a pre-
removal survey to detect the presence of turtles and marine mammals, a 
description of the proposed detection method; and
    (4) A statement whether or not you will use transducers to measure 
the pressure and impulse of the detonations.
    (g) Your plans for transportation and disposal (including as an 
artificial reef) or salvage of the removed platform.
    (h) If available, the results of any recent biological surveys 
conducted in the vicinity of the structure and recent observations of 
turtles or marine mammals at the structure site.
    (i) Your plans to protect archaeological and sensitive biological 
features during removal operations, including a brief assessment of the 
environmental impacts of the removal operations and procedures and 
mitigation measures you will take to minimize such impacts.
    (j) A statement whether or not you will use divers to survey the 
area after removal to determine any effects on marine life.

Sec.  250.1728  To what depth must I remove a platform or other 
facility?

    (a) Unless the Regional Supervisor approves an alternate depth 
under paragraph (b) of this section, you must remove all platforms and 
other facilities (including templates and pilings) to at least 15 feet 
below the mud line.
    (b) The Regional Supervisor may approve an alternate removal depth 
if:
    (1) The remaining structure would not become an obstruction to 
other users of the seafloor or area, and geotechnical and other 
information you provide demonstrate that erosional processes capable of 
exposing the obstructions are not expected; or
    (2) You determine, and BSEE concurs, that you must use divers and 
the seafloor sediment stability poses safety concerns; or
    (3) The water depth is greater than 800 meters (2,624 feet).

Sec.  250.1729  After I remove a platform or other facility, what 
information must I submit?

    Within 30 days after you remove a platform or other facility, you 
must submit a written report to the Regional Supervisor that includes 
the following:
    (a) A summary of the removal operation including the date it was 
completed;
    (b) A description of any mitigation measures you took; and
    (c) A statement signed by your authorized representative that 
certifies that the types and amount of explosives you used in removing 
the platform or other facility were consistent with those set forth in 
the approved removal application.

Sec.  250.1730  When might BSEE approve partial structure removal or 
toppling in place?

    The Regional Supervisor may grant a departure from the requirement 
to remove a platform or other facility by approving partial structure 
removal or toppling in place for conversion to an artificial reef if 
you meet the following conditions:
    (a) The structure becomes part of a State artificial reef program, 
and the responsible State agency acquires a permit from the U.S. Army 
Corps of Engineers and accepts title and liability for the structure; 
and
    (b) You satisfy any U.S. Coast Guard (USCG) navigational 
requirements for the structure.

Sec.  250.1731  Who is responsible for decommissioning an OCS facility 
subject to an Alternate Use RUE?

    (a) The holder of an Alternate Use RUE issued under 30 CFR part 585 
is responsible for all decommissioning obligations that accrue 
following the issuance of the Alternate Use RUE and which pertain to 
the Alternate Use RUE. See 30 CFR part 585, subpart J, for additional 
information concerning the decommissioning responsibilities of an 
Alternate Use RUE grant holder.
    (b) The lessee under the lease originally issued under 30 CFR part 
556 will remain responsible for decommissioning obligations that 
accrued before issuance of the Alternate Use RUE, as well as for 
decommissioning obligations that accrue following issuance of the 
Alternate Use RUE to the extent associated with continued activities 
authorized under this part.
    (c) If a lease issued under 30 CFR part 556 is cancelled or 
otherwise terminated under any provision of this subchapter, the 
lessee, upon our approval, may defer removal of any OCS facility within 
the lease area that is subject to an Alternate Use RUE. If we elect to 
grant such a deferral, the lessee remains responsible for removing the 
facility upon termination of the Alternate Use RUE and will be required 
to retain sufficient bonding or other financial assurances to ensure 
that the structure is removed or otherwise decommissioned in accordance 
with the provisions of this subpart.

[[Page 64592]]

Site Clearance for Wells, Platforms, and Other Facilities

Sec.  250.1740  How must I verify that the site of a permanently 
plugged well, removed platform, or other removed facility is clear of 
obstructions?

    Within 60 days after you permanently plug a well or remove a 
platform or other facility, you must verify that the site is clear of 
obstructions by using one of the following methods:
    (a) For a well site, you must either:
    (1) Drag a trawl over the site;
    (2) Scan across the location using sonar equipment;
    (3) Inspect the site using a diver;
    (4) Videotape the site using a camera on a remotely operated 
vehicle (ROV); or
    (5) Use another method approved by the District Manager if the 
particular site conditions warrant.
    (b) For a platform or other facility site in water depths less than 
300 feet, you must drag a trawl over the site.
    (c) For a platform or other facility site in water depths 300 feet 
or more, you must either:
    (1) Drag a trawl over the site;
    (2) Scan across the site using sonar equipment; or
    (3) Use another method approved by the Regional Supervisor if the 
particular site conditions warrant.

Sec.  250.1741  If I drag a trawl across a site, what requirements must 
I meet?

    If you drag a trawl across the site in accordance with Sec.  
250.1740, you must meet all of the requirements of this section.
    (a) You must drag the trawl in a grid-like pattern as shown in the 
following table:

------------------------------------------------------------------------
                                               You must drag the trawl
                For a . . .                        across a . . .
------------------------------------------------------------------------
(1) Well site,                              300-foot-radius circle
                                             centered on the well
                                             location.
(2) Subsea well site,                       600-foot-radius circle
                                             centered on the well
                                             location.
(3) Platform site,                          1,320-foot-radius circle
                                             centered on the location of
                                             the platform.
(4) Single-well caisson, well protector     600-foot-radius circle
 jacket, template, or manifold,              centered on the structure
                                             location.
------------------------------------------------------------------------

     (b) You must trawl 100 percent of the limits described in 
paragraph (a) of this section in two directions.
    (c) You must mark the area to be cleared as a hazard to navigation 
according to USCG requirements until you complete the site clearance 
procedures.
    (d) You must use a trawling vessel equipped with a calibrated 
navigational positioning system capable of providing position accuracy 
of 30 feet.
    (e) You must use a trawling net that is representative of those 
used in the commercial fishing industry (one that has a net strength 
equal or greater than that provided by No. 18 twine).
    (f) You must ensure that you trawl no closer than 300 feet from a 
shipwreck, and 500 feet from a sensitive biological feature.
    (g) If you trawl near an active pipeline, you must meet the 
requirements in the following table:

----------------------------------------------------------------------------------------------------------------
                For . . .                            You must trawl . . .                 And you must . . .
----------------------------------------------------------------------------------------------------------------
(1) Buried active pipelines,               ........................................  First contact the pipeline
                                                                                      owner or operator to
                                                                                      determine the condition of
                                                                                      the pipeline before
                                                                                      trawling over the buried
                                                                                      pipeline.
(2) Unburied active pipelines that are 8   no closer than 100 feet to the either     Trawl parallel to the
 inches in diameter or larger,              side of the pipeline,                     pipeline Do not trawl
                                                                                      across the pipeline.
(3) Unburied smaller diameter active       no closer than 100 feet to either side    Trawl parallel to the
 pipelines in the trawl area that have      of the pipeline,                          pipeline. Do not trawl
 obstructions (e.g., pipeline valves)                                                 across the pipeline.
 present,
(4) Unburied active pipelines in the       parallel to the pipeline,                 ...........................
 trawl area that are smaller than 8
 inches in diameter and have no
 obstructions present,
----------------------------------------------------------------------------------------------------------------

     (h) You must ensure that any trawling contractor you may use:
    (1) Has no corporate or other financial ties to you; and
    (2) Has a valid commercial trawling license for both the vessel and 
its captain.

Sec.  250.1742  What other methods can I use to verify that a site is 
clear?

    If you do not trawl a site, you can verify that the site is clear 
of obstructions by using any of the methods shown in the following 
table:

----------------------------------------------------------------------------------------------------------------
             If you use . . .                           You must . . .                    And you must . . .
----------------------------------------------------------------------------------------------------------------
(a) Sonar,                                 cover 100 percent of the appropriate      Use a sonar signal with a
                                            grid area listed in Sec.   250.1741(a),   frequency of at least 500
                                                                                      kHz.
(b) A diver,                               ensure that the diver visually inspects   Ensure that the diver uses
                                            100 percent of the appropriate grid       a search pattern of
                                            area listed in Sec.   250.1741(a),        concentric circles or
                                                                                      parallel lines spaced no
                                                                                      more than 10 feet apart.
(c) An ROV (remotely operated vehicle),    ensure that the ROV camera records        Ensure that the ROV uses a
                                            videotape over 100 percent of the         pattern of concentric
                                            appropriate grid area listed in Sec.      circles or parallel lines
                                            250.1741(a),                              spaced no more than 10
                                                                                      feet apart.
----------------------------------------------------------------------------------------------------------------

[[Page 64593]]

Sec.  250.1743  How do I certify that a site is clear of obstructions?

    (a) For a well site, you must submit to the appropriate District 
Manager within 30 days after you complete the verification activities a 
form BSEE-0124, Application for Permit to Modify, to include the 
following information:
    (1) A signed certification that the well site area is cleared of 
all obstructions;
    (2) The date the verification work was performed and the vessel 
used;
    (3) The extent of the area surveyed;
    (4) The survey method used;
    (5) The results of the survey, including a list of any debris 
removed or a statement from the trawling contractor that no objects 
were recovered; and
    (6) A post-trawling job plot or map showing the trawled area.
    (b) For a platform or other facility site, you must submit the 
following information to the appropriate Regional Supervisor within 30 
days after you complete the verification activities:
    (1) A letter signed by an authorized company official certifying 
that the platform or other facility site area is cleared of all 
obstructions and that a company representative witnessed the 
verification activities;
    (2) A letter signed by an authorized official of the company that 
performed the verification work for you certifying that it cleared the 
platform or other facility site area of all obstructions;
    (3) The date the verification work was performed and the vessel 
used;
    (4) The extent of the area surveyed;
    (5) The survey method used;
    (6) The results of the survey, including a list of any debris 
removed or a statement from the trawling contractor that no objects 
were recovered; and
    (7) A post-trawling job plot or map showing the trawled area.

Pipeline Decommissioning

Sec.  250.1750  When may I decommission a pipeline in place?

    You may decommission a pipeline in place when the Regional 
Supervisor determines that the pipeline does not constitute a hazard 
(obstruction) to navigation and commercial fishing operations, unduly 
interfere with other uses of the OCS, or have adverse environmental 
effects.

Sec.  250.1751  How do I decommission a pipeline in place?

    You must do the following to decommission a pipeline in place:
    (a) Submit a pipeline decommissioning application in triplicate to 
the Regional Supervisor for approval. Your application must be 
accompanied by payment of the service fee listed in Sec.  250.125. Your 
application must include the following information:
    (1) Reason for the operation;
    (2) Proposed decommissioning procedures;
    (3) Length (feet) of segment to be decommissioned; and
    (4) Length (feet) of segment remaining.
    (b) Pig the pipeline, unless the Regional Supervisor determines 
that pigging is not practical;
    (c) Flush the pipeline;
    (d) Fill the pipeline with seawater;
    (e) Cut and plug each end of the pipeline;
    (f) Bury each end of the pipeline at least 3 feet below the 
seafloor or cover each end with protective concrete mats, if required 
by the Regional Supervisor; and
    (g) Remove all pipeline valves and other fittings that could unduly 
interfere with other uses of the OCS.

Sec.  250.1752  How do I remove a pipeline?

    Before removing a pipeline, you must:
    (a) Submit a pipeline removal application in triplicate to the 
Regional Supervisor for approval. Your application must be accompanied 
by payment of the service fee listed in Sec.  250.125. Your application 
must include the following information:
    (1) Proposed removal procedures;
    (2) If the Regional Supervisor requires it, a description, 
including anchor pattern(s), of the vessel(s) you will use to remove 
the pipeline;
    (3) Length (feet) to be removed;
    (4) Length (feet) of the segment that will remain in place;
    (5) Plans for transportation of the removed pipe for disposal or 
salvage;
    (6) Plans to protect archaeological and sensitive biological 
features during removal operations, including a brief assessment of the 
environmental impacts of the removal operations and procedures and 
mitigation measures that you will take to minimize such impacts; and
    (7) Projected removal schedule and duration.
    (b) Pig the pipeline, unless the Regional Supervisor determines 
that pigging is not practical; and
    (c) Flush the pipeline.

Sec.  250.1753  After I decommission a pipeline, what information must 
I submit?

    Within 30 days after you decommission a pipeline, you must submit a 
written report to the Regional Supervisor that includes the following:
    (a) A summary of the decommissioning operation including the date 
it was completed;
    (b) A description of any mitigation measures you took; and
    (c) A statement signed by your authorized representative that 
certifies that the pipeline was decommissioned according to the 
approved application.

Sec.  250.1754  When must I remove a pipeline decommissioned in place?

    You must remove a pipeline decommissioned in place if the Regional 
Supervisor determines that the pipeline is an obstruction.

Subpart R [Reserved]

Subpart S--Safety and Environmental Management Systems (SEMS)

Sec.  250.1900  Must I have a SEMS program?

    You must develop, implement, and maintain a safety and 
environmental management system (SEMS) program. Your SEMS program must 
address the elements described in Sec.  250.1902, American Petroleum 
Institute's Recommended Practice for Development of a Safety and 
Environmental Management Program for Offshore Operations and Facilities 
(API RP 75) (as incorporated by reference in Sec.  250.198), and other 
requirements as identified in this subpart.
    (a) You must comply with the provisions of this subpart and have 
your SEMS program in effect on or before November 15, 2011, except for 
the submission of Form BSEE-0131 as required in Sec.  250.1929.
    (b) You must submit Form BSEE-0131 on an annual basis beginning 
March 31, 2011.
    (c) If there are any conflicts between the requirements of this 
subpart and API RP 75 (as incorporated by reference in Sec.  250.198), 
you must follow the requirements of this subpart.
    (d) Nothing in this subpart affects safety or other matters under 
the jurisdiction of the Coast Guard.

Sec.  250.1901  What is the goal of my SEMS program?

    The goal of your SEMS program is to promote safety and 
environmental protection by ensuring all personnel aboard a facility 
are complying with the policies and procedures identified in your SEMS.
    (a) To accomplish this goal, you must ensure that your SEMS program 
identifies, addresses, and manages safety, environmental hazards, and 
impacts during the design, construction, start-up, operation, 
inspection, and maintenance of all new and existing facilities, 
including mobile offshore drilling units (MODU) while under BSEE 
jurisdiction and Department of Interior (DOI) regulated pipelines.

[[Page 64594]]

    (b) All personnel involved with your SEMS program must be trained 
to have the skills and knowledge to perform their assigned duties.

Sec.  250.1902  What must I include in my SEMS program?

    You must have a properly documented SEMS program in place and make 
it available to BSEE upon request as required by Sec.  250.1924(b).
    (a) Your SEMS program must meet the minimum criteria outlined in 
this subpart, including the following SEMS program elements:
    (1) General (see Sec.  250.1909)
    (2) Safety and Environmental Information (see Sec.  250.1910)
    (3) Hazards Analysis (see Sec.  250.1911)
    (4) Management of Change (see Sec.  250.1912)
    (5) Operating Procedures (see Sec.  250.1913)
    (6) Safe Work Practices (see Sec.  250.1914)
    (7) Training (see Sec.  250.1915)
    (8) Mechanical Integrity (Assurance of Quality and Mechanical 
Integrity of Critical Equipment) (see Sec.  250.1916)
    (9) Pre-startup Review (see Sec.  250.1917)
    (10) Emergency Response and Control (see Sec.  250.1918)
    (11) Investigation of Incidents (see Sec.  250.1919)
    (12) Auditing (Audit of Safety and Environmental Management Program 
Elements) (see Sec. Sec.  250.1920)
    (13) Recordkeeping (Records and Documentation) and additional BSEE 
requirements (see Sec.  250.1928).
    (b) You must also include a job safety analysis (JSA) for OCS 
activities identified or discussed in your SEMS program (see Sec.  
250.1911(b)).
    (c) Your SEMS program must meet or exceed the standards of safety 
and environmental protection of API RP 75 (as incorporated by reference 
in Sec.  250.198).

Sec.  250.1903  Definitions.

    Definitions listed in this section apply to this subpart and 
supersede definitions in API RP 75, Appendices D and E (as incorporated 
by reference in Sec.  250.198).
    Designated and qualified personnel means employees (not 
contractors) that are knowledgeable of your program, and have actual 
work experience and training in implementing and auditing a SEMS or a 
similar program in an offshore oil and gas environment.
    Personnel means direct employee(s) of the operator and contracted 
workers who are involved with or affected by specific jobs or tasks.

Sec.  250.1904  Documents incorporated by reference.

    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. 
If any incorporated document uses the word ``should'', it means must 
for purposes of these regulations.

Sec. Sec.  250.1905-250.1908   [Reserved]

Sec.  250.1909  What are management's general responsibilities for the 
SEMS program?

    You, through your management, must require that the program 
elements discussed in API RP 75 (as incorporated by reference in Sec.  
250.198) and in this subpart are properly documented and are available 
at field and office locations, as appropriate for each program element. 
You, through your management, are responsible for the development, 
support, continued improvement, and overall success of your SEMS 
program. Specifically you, through your management, must:
    (a) Establish goals and performance measures, demand accountability 
for implementation, and provide necessary resources for carrying out an 
effective SEMS program.
    (b) Appoint management representatives who are responsible for 
establishing, implementing and maintaining an effective SEMS program.
    (c) Designate specific management representatives who are 
responsible for reporting to management on the performance of the SEMS 
program.
    (d) At intervals specified in the SEMS program and at least 
annually, review the SEMS program to determine if it continues to be 
suitable, adequate and effective (by addressing the possible need for 
changes to policy, objectives, and other elements of the program in 
light of program audit results, changing circumstances and the 
commitment to continual improvement) and document the observations, 
conclusions and recommendations of that review.
    (e) Develop and endorse a written description of your safety and 
environmental policies and organizational structure that define 
responsibilities, authorities, and lines of communication required to 
implement the SEMS program.
    (f) Utilize personnel with expertise in identifying safety hazards, 
environmental impacts, optimizing operations, developing safe work 
practices, developing training programs and investigating incidents.
    (g) Ensure that facilities are designed, constructed, maintained, 
monitored, and operated in a manner compatible with applicable industry 
codes, consensus standards, and generally accepted practice as well as 
in compliance with all applicable governmental regulations.
    (h) Ensure that management of safety hazards and environmental 
impacts is an integral part of the design, construction, maintenance, 
operation, and monitoring of each facility.
    (i) Ensure that suitably trained and qualified personnel are 
employed to carry out all aspects of the SEMS program.
    (j) Ensure that the SEMS program is maintained and kept up to date 
by means of periodic audits to ensure effective performance.

Sec.  250.1910  What safety and environmental information is required?

    (a) You must require that SEMS program safety and environmental 
information be developed and maintained for any facility that is 
subject to the SEMS program.
    (b) SEMS program safety and environmental information must include:
    (1) Information that provides the basis for implementing all SEMS 
program elements, including the requirements of hazard analysis (Sec.  
250.1911);
    (2) process design information including, as appropriate, a 
simplified process flow diagram and acceptable upper and lower limits, 
where applicable, for items such as temperature, pressure, flow and 
composition; and
    (3) mechanical design information including, as appropriate, piping 
and instrument diagrams; electrical area classifications; equipment 
arrangement drawings; design basis of the relief system; description of 
alarm, shutdown, and interlock systems; description of well control 
systems; and design basis for passive and active fire protection 
features and systems and emergency evacuation procedures.

Sec.  250.1911  What criteria for hazards analyses must my SEMS program 
meet?

    You must ensure the development and implementation of a hazards 
analysis (facility level) and a job safety analysis (operations/task 
level) for all of your facilities. For this subpart, facilities include 
all types of offshore structures permanently or temporarily attached to 
the seabed (i.e., mobile offshore drilling units; floating production 
systems;

[[Page 64595]]

floating production, storage and offloading facilities; tension-leg 
platforms; and spars) used for exploration, development, production, 
and transportation activities for oil, gas, or sulphur from areas 
leased in the OCS. Facilities also include DOI regulated pipelines. You 
must document and maintain current analyses for each operation covered 
by this section for the life of the operation at the facility. The 
analyses must be updated when an internal audit is conducted to ensure 
that it is consistent with the current operations on your facility. 
Hazards analysis requirements for simple and nearly identical 
facilities, such as well jackets and single well caissons, may be 
fulfilled by performing a single hazards analysis which you can apply 
to all such facilities after you verify that any site specific 
deviations are addressed in each of the elements of your SEMS program.
    (a) Hazards Analysis (facility level). For a hazards analysis 
(facility level), you must perform an initial hazards analysis on each 
facility on or before November 15, 2011. The hazards analysis must be 
appropriate to the complexity of the operation and must identify, 
evaluate, and manage the hazards involved in the operation.
    (1) The hazards analysis must address the following:
    (i) Hazards of the operation;
    (ii) Previous incidents related to the operation you are 
evaluating, including any incident in which you were issued an Incident 
of Noncompliance or a civil or criminal penalty;
    (iii) Control technology applicable to the operation your hazards 
analysis is evaluating; and
    (iv) A qualitative evaluation of the possible safety and health 
effects on employees, and potential impacts to the human and marine 
environments, which may result if the control technology fails.
    (2) The hazards analysis must be performed by a person(s) with 
experience in the operations being evaluated. These individuals also 
need to be experienced in the hazards analysis methodologies being 
employed.
    (3) You should assure that the recommendations in the hazards 
analysis are resolved and that the resolution is documented.
    (b) Job Safety Analysis (JSA). You must develop and implement a JSA 
for OCS activities identified or discussed in your SEMS program.
    (1) You must keep a copy of the most recent JSA (operations/task 
level) at the job site and it must be readily accessible to employees.
    (2) Your JSA must identify, analyze, and record:
    (i) The steps involved in performing a specific job;
    (ii) the existing or potential safety and health hazards associated 
with each step; and
    (iii) the recommended action(s)/procedure(s) that will eliminate or 
reduce these hazards and the risk of a workplace injury or illness.
    (3) The supervisor of the person in charge of the task must approve 
the JSA prior to the commencement of the work.

Sec.  250.1912  What criteria for management of change must my SEMS 
program meet?

    (a) You must develop and implement written management of change 
procedures for modifications associated with the following:
    (1) Equipment,
    (2) Operating procedures,
    (3) Personnel changes (including contractors),
    (4) Materials, and
    (5) Operating conditions.
    (b) Management of change procedures do not apply to situations 
involving replacement in kind (such as, replacement of one component by 
another component with the same performance capabilities).
    (c) You must review all changes prior to their implementation.
    (d) The following items must be included in your management of 
change procedures:
    (1) The technical basis for the change;
    (2) Impact of the change on safety, health, and the coastal and 
marine environments;
    (3) Necessary time period to implement the change; and
    (4) Management approval procedures for the change.
    (e) Employees, including contractors whose job tasks will be 
affected by a change in the operation, must be informed of, and trained 
in, the change prior to startup of the process or affected part of the 
operation; and
    (f) If a management of change results in a change in the operating 
procedures of your SEMS program, such changes must be documented and 
dated.

Sec.  250.1913  What criteria for operating procedures must my SEMS 
program meet?

    (a) You must develop and implement written operating procedures 
that provide instructions for conducting safe and environmentally sound 
activities involved in each operation addressed in your SEMS program. 
These procedures must include the job title and reporting relationship 
of the person or persons responsible for each of the facility's 
operating areas and address the following:
    (1) Initial startup;
    (2) Normal operations;
    (3) All emergency operations (including but not limited to medical 
evacuations, weather-related evacuations and emergency shutdown 
operations);
    (4) Normal shutdown;
    (5) Startup following a turnaround, or after an emergency shutdown;
    (6) Bypassing and flagging out-of-service equipment;
    (7) Safety and environmental consequences of deviating from your 
equipment operating limits and steps required to correct or avoid this 
deviation;
    (8) Properties of, and hazards presented by, the chemicals used in 
the operations;
    (9) Precautions you will take to prevent the exposure of chemicals 
used in your operations to personnel and the environment. The 
precautions must include control technology, personal protective 
equipment, and measures to be taken if physical contact or airborne 
exposure occurs;
    (10) Raw materials used in your operations and the quality control 
procedures you used in purchasing these raw materials;
    (11) Control of hazardous chemical inventory; and
    (12) Impacts to the human and marine environment identified through 
your hazards analysis.
    (b) Operating procedures must be accessible to all employees 
involved in the operations.
    (c) Operating procedures must be reviewed at the conclusion of 
specified periods and as often as necessary to assure they reflect 
current and actual operating practices, including any changes made to 
your operations.
    (d) You must develop and implement safe and environmentally sound 
work practices for identified hazards during operations and the degree 
of hazard presented.
    (e) Review of and changes to the procedures must be documented and 
communicated to responsible personnel.

Sec.  250.1914  What criteria must be documented in my SEMS program for 
safe work practices and contractor selection?

    Your SEMS program must establish and implement safe work practices 
designed to minimize the risks associated with operating, maintenance, 
and modification activities and the handling of materials and 
substances that could affect safety or the environment. Your SEMS 
program must also document contractor selection criteria. When 
selecting a contractor, you must obtain and evaluate

[[Page 64596]]

information regarding the contractor's safety and environmental 
performance. Operators must ensure that contractors have their own 
written safe work practices. Contractors may adopt appropriate sections 
of the operator's SEMS program. Operator and contractor must document 
their agreement on appropriate contractor safety and environmental 
policies and practices before the contractor begins work at the 
operator's facilities.
    (a) A contractor is anyone performing work for the lessee. However, 
these requirements do not apply to contractors providing domestic 
services to the lessee or other contractors. Domestic services include 
janitorial work, food and beverage service, laundry service, 
housekeeping, and similar activities.
    (b) You must document that your contracted employees are 
knowledgeable and experienced in the work practices necessary to 
perform their job in a safe and environmentally sound manner. 
Documentation of each contracted employee's expertise to perform his/
her job and a copy of the contractor's safety policies and procedures 
must be made available to the operator and BSEE upon request.
    (c) Your SEMS program must include procedures and verification for 
selecting a contractor as follows:
    (1) Your SEMS program must have procedures that verify that 
contractors are conducting their activities in accordance with your 
SEMS program.
    (2) You are responsible for making certain that contractors have 
the skills and knowledge to perform their assigned duties and are 
conducting these activities in accordance with the requirements in your 
SEMS program.
    (3) You must make the results of your verification for selecting 
contractors available to BSEE upon request.
    (d) Your SEMS program must include procedures and verification that 
contractor personnel understand and can perform their assigned duties 
for activities such as, but not limited to:
    (1) Installation, maintenance, or repair of equipment;
    (2) Construction, startup, and operation of your facilities;
    (3) Turnaround operations;
    (4) Major renovation; or
    (5) Specialty work.
    (e) You must:
    (1) Perform periodic evaluations of the performance of contract 
employees that verifies they are fulfilling their obligations, and
    (2) Maintain a contractor employee injury and illness log for 2 
years related to the contractor's work in the operation area, and 
include this information on Form BSEE-0131.
    (f) You must inform your contractors of any known hazards at the 
facility they are working on including, but not limited to fires, 
explosions, slips, trips, falls, other injuries, and hazards associated 
with lifting operations.
    (g) You must develop and implement safe work practices to control 
the presence, entrance, and exit of contract employees in operation 
areas.

Sec.  250.1915  What criteria for training must be in my SEMS program?

    Your SEMS program must establish and implement a training program 
so that all personnel are trained to work safely and are aware of 
environmental considerations offshore, in accordance with their duties 
and responsibilities. Training must address the operating procedures 
(Sec.  250.1913), the safe work practices (Sec.  250.1914), and the 
emergency response and control measures (Sec.  250.1918). You must 
document the qualifications of your instructors. Your SEMS program must 
address:
    (a) Initial training for the basic well-being of personnel and 
protection of the environment, and ensure that persons assigned to 
operate and maintain the facility possess the required knowledge and 
skills to carry out their duties and responsibilities, including 
startup and shutdown.
    (b) Periodic training to maintain understanding of, and adherence 
to, the current operating procedures, using periodic drills, to verify 
adequate retention of the required knowledge and skills.
    (c) Communication requirements to ensure that whenever a change is 
made to operating procedures (Sec.  250.1913), the safe work practices 
(Sec.  250.1914), or the emergency response and control measures (Sec.  
250.1918), personnel will be trained in or otherwise informed of the 
change before they are expected to operate the facility.
    (d) How you will verify that the contractors are trained in the 
work practices necessary to perform their jobs in a safe and 
environmentally sound manner, including training on operating 
procedures (Sec.  250.1913), the safe work practices (Sec.  250.1914), 
or the emergency response and control measures (Sec.  250.1918).

Sec.  250.1916  What criteria for mechanical integrity must my SEMS 
program meet?

    You must develop and implement written procedures that provide 
instructions to ensure the mechanical integrity and safe operation of 
equipment through inspection, testing, and quality assurance. The 
purpose of mechanical integrity is to ensure that equipment is fit for 
service. Your mechanical integrity program must encompass all equipment 
and systems used to prevent or mitigate uncontrolled releases of 
hydrocarbons, toxic substances, or other materials that may cause 
environmental or safety consequences. These procedures must address the 
following:
    (a) The design, procurement, fabrication, installation, 
calibration, and maintenance of your equipment and systems in 
accordance with the manufacturer's design and material specifications.
    (b) The training of each employee involved in maintaining your 
equipment and systems so that your employees can implement your 
mechanical integrity program.
    (c) The frequency of inspections and tests of your equipment and 
systems. The frequency of inspections and tests must be in accordance 
with BSEE regulations and meet the manufacturer's recommendations. 
Inspections and tests can be performed more frequently if determined to 
be necessary by prior operating experience.
    (d) The documentation of each inspection and test that has been 
performed on your equipment and systems. This documentation must 
identify the date of the inspection or test; include the name and 
position, and the signature of the person who performed the inspection 
or test; include the serial number or other identifier of the equipment 
on which the inspection or test was performed; include a description of 
the inspection or test performed; and the results of the inspection 
test.
    (e) The correction of deficiencies associated with equipment and 
systems that are outside the manufacturer's recommended limits. Such 
corrections must be made before further use of the equipment and 
system.
    (f) The installation of new equipment and constructing systems. The 
procedures must address the application for which they will be used.
    (g) The modification of existing equipment and systems. The 
procedures must ensure that they are modified for the application for 
which they will be used.
    (h) The verification that inspections and tests are being 
performed. The procedures must be appropriate to ensure that equipment 
and systems are installed consistent with design specifications and the 
manufacturer's instructions.
    (i) The assurance that maintenance materials, spare parts, and 
equipment

[[Page 64597]]

are suitable for the applications for which they will be used.

Sec.  250.1917  What criteria for pre-startup review must be in my SEMS 
program?

    Your SEMS program must require that the commissioning process 
include a pre-startup safety and environmental review for new and 
significantly modified facilities that are subject to this subpart to 
confirm that the following criteria are met:
    (a) Construction and equipment are in accordance with applicable 
specifications.
    (b) Safety, environmental, operating, maintenance, and emergency 
procedures are in place and are adequate.
    (c) Safety and environmental information is current.
    (d) Hazards analysis recommendations have been implemented as 
appropriate.
    (e) Training of operating personnel has been completed.
    (f) Programs to address management of change and other elements of 
this subpart are in place.
    (g) Safe work practices are in place.

Sec.  250.1918  What criteria for emergency response and control must 
be in my SEMS program?

    Your SEMS program must require that emergency response and control 
plans are in place and are ready for immediate implementation. These 
plans must be validated by drills carried out in accordance with a 
schedule defined by the SEMS training program (Sec.  250.1915). The 
SEMS emergency response and control plans must include:
    (a) Emergency Action Plan that assigns authority and responsibility 
to the appropriate qualified person(s) at a facility for initiating 
effective emergency response and control, addressing emergency 
reporting and response requirements, and complying with all applicable 
governmental regulations;
    (b) Emergency Control Center(s) designated for each facility with 
access to the Emergency Action Plans, oil spill contingency plan, and 
other safety and environmental information (Sec.  250.1910); and
    (c) Training and Drills incorporating emergency response and 
evacuation procedures conducted periodically for all personnel 
(including contractor's personnel), as required by the SEMS training 
program (Sec.  250.1915). Drills must be based on realistic scenarios 
conducted periodically to exercise elements contained in the facility 
or area emergency action plan. An analysis and critique of each drill 
must be conducted to identify and correct weaknesses.

Sec.  250.1919  What criteria for investigation of incidents must be in 
my SEMS program?

    To learn from incidents and help prevent similar incidents, your 
SEMS program must establish procedures for investigation of all 
incidents with serious safety or environmental consequences and require 
investigation of incidents that are determined by facility management 
or BSEE to have possessed the potential for serious safety or 
environmental consequences. Incident investigations must be initiated 
as promptly as possible, with due regard for the necessity of securing 
the incident scene and protecting people and the environment. Incident 
investigations must be conducted by personnel knowledgeable in the 
process involved, investigation techniques, and other specialties that 
are relevant or necessary.
    (a) The investigation of an incident must address the following:
    (1) The nature of the incident;
    (2) The factors (human or other) that contributed to the initiation 
of the incident and its escalation/control; and
    (3) Recommended changes identified as a result of the 
investigation.
    (b) A corrective action program must be established based on the 
findings of the investigation in order to analyze incidents for common 
root causes. The corrective action program must:
    (1) Retain the findings of investigations for use in the next 
hazard analysis update or audit;
    (2) Determine and document the response to each finding to ensure 
that corrective actions are completed; and
    (3) Implement a system whereby conclusions of investigations are 
distributed to similar facilities and appropriate personnel within 
their organization.

Sec.  250.1920  What are the auditing requirements for my SEMS program?

    (a) You must have your SEMS program audited by either an 
independent third-party or your designated and qualified personnel 
according to the requirements of this subpart and API RP 75, Section 12 
(as incorporated by reference in Sec.  250.198) within 2 years of the 
initial implementation of the SEMS program and at least once every 3 
years thereafter. The audit must be a comprehensive audit of all 
thirteen elements of your SEMS program to evaluate compliance with the 
requirements of this subpart and API RP 75 to identify areas in which 
safety and environmental performance needs to be improved.
    (b) Your audit plan and procedures must meet or exceed all of the 
recommendations included in API RP 75 section 12 (as specified in Sec.  
250.198) and include information on how you addressed those 
recommendations. You must specifically address the following items:
    (1) Section 12.1 General.
    (2) Section 12.2 Scope.
    (3) Section 12.3 Audit Coverage.
    (4) Section 12.4 Audit Plan. You must submit your written Audit 
Plan to BSEE at least 30 days before the audit. BSEE reserves the right 
to modify the list of facilities that you propose to audit.
    (5) Section 12.5 Audit Frequency, except your audit interval must 
not exceed 3 years after the 2 year time period for the first audit.
    (6) Section 12.6 Audit Team. The audit that you submit to BSEE must 
be conducted by either an independent third party or your designated 
and qualified personnel. The independent third party or your designated 
and qualified personnel must meet the requirements in Sec.  250.1926.
    (c) You must require your auditor (independent third party or your 
designated and qualified personnel) to submit an audit report of the 
findings and conclusions of the audit to BSEE within 30 days of the 
audit completion date. The report must outline the results of the 
audit, including deficiencies identified.
    (d) You must provide the BSEE a copy of your plan for addressing 
the deficiencies identified in your audit within 30 days of completion 
of the audit. Your plan must address the following:
    (1) A proposed schedule to correct the deficiencies identified in 
the audit. BSEE will notify you within 14 days of receipt of your plan 
if your proposed schedule is not acceptable.
    (2) The person responsible for correcting each identified 
deficiency, including their job title.
    (e) BSEE may verify that you undertook the corrective actions and 
that these actions effectively address the audit findings.

Sec. Sec.  250.1921-250.1923  [Reserved]

Sec.  250.1924  How will BSEE determine if my SEMS program is 
effective?

    (a) BSEE or its authorized representative may evaluate or visit 
your facility to determine whether your SEMS program is in place, 
addresses all required elements, and is effective in protecting the 
safety and health of workers, the environment, and preventing 
incidents. BSEE or its authorized representative may evaluate your SEMS 
program, including documentation of contractors,

[[Page 64598]]

independent third parties, your designated and qualified personnel, and 
audit reports, to assess your SEMS program. These evaluations or visits 
may be random or based upon the OCS lease operator's or contractor's 
performance.
    (b) For the evaluations, you must make the following available to 
BSEE upon request:
    (1) Your SEMS program;
    (2) The qualifications of your independent third-party or your 
designated and qualified personnel;
    (3) The SEMS audits conducted of your program;
    (4) Documents or information relevant to whether you have addressed 
and corrected the deficiencies of your audit; and
    (5) Other relevant documents or information.
    (c) During the site visit BSEE may verify that:
    (1) Personnel are following your SEMS program,
    (2) You can explain and demonstrate the procedures and policies 
included in your SEMS program; and
    (3) You can produce evidence to support the implementation of your 
SEMS program.
    (d) Representatives from BSEE may observe or participate in your 
SEMS audit. You must notify the BSEE at least 30 days prior to 
conducting your audit as required in Sec.  250.1920, so that BSEE may 
make arrangements to observe or participate in the audit.

Sec.  250.1925  May BSEE direct me to conduct additional audits?

    (a) If BSEE identifies safety or non-compliance concerns based on 
the results of our inspections and evaluations, or as a result of an 
event, BSEE may direct you to have an independent third-party audit of 
your SEMS program, in addition to the regular audit required by Sec.  
250.1920, or BSEE may conduct an audit.
    (1) If BSEE direct you to have an independent third-party audit,
    (i) You are responsible for all of the costs associated with the 
audit, and
    (ii) The independent third-party audit must meet the requirements 
of Sec.  250.1920 of this part and you must ensure that the independent 
third party submits the findings and conclusions of a BSEE-directed 
audit according to the requirements in Sec.  250.1920 to BSEE within 30 
days after the audit is completed.
    (2) If BSEE conducts the audit, BSEE will provide a report of the 
findings and conclusions within 30 days of the audit.
    (b) Findings from these audits may result in enforcement actions as 
identified in Sec.  250.1927.
    (c) You must provide the BSEE a copy of your plan for addressing 
the deficiencies identified in the BSEE-directed audit within 30 days 
of completion of the audit as required in Sec.  250.1920.

Sec.  250.1926  What qualifications must an independent third party or 
my designated and qualified personnel meet?

    (a) You must either choose an independent third-party or your 
designated and qualified personnel to audit your SEMS program. You must 
take into account the following qualifications when selecting the 
third-party or your designated and qualified personnel:
    (1) Previous education and experience with SEMS, or similar 
management related programs.
    (2) Technical capabilities of the individual or organization for 
the specific project.
    (3) Ability to perform the independent third-party functions for 
the specific project considering current commitments.
    (4) Previous experience with BSEE regulatory requirements and 
procedures.
    (5) Previous education and experience to comprehend and evaluate 
how the company's offshore activities, raw materials, production 
methods and equipment, products, byproducts, and business management 
systems may impact health and safety performance in the workplace.
    (b) You must have procedures to avoid conflicts of interest related 
to the development of your SEMS program and the independent third party 
auditor and your designated and qualified personnel.
    (c) BSEE may evaluate the qualifications of the independent third 
parties or your designated and qualified personnel. This may include an 
audit of documents and procedures or interviews. BSEE may disallow 
audits by a specific independent third-party or your designated and 
qualified personnel if they do not meet the criteria of this section.

Sec.  250.1927  What happens if BSEE finds shortcomings in my SEMS 
program?

    If BSEE determines that your SEMS program is not in compliance with 
this subpart we may initiate one or more of the following enforcement 
actions:
    (a) Issue an Incident(s) of Noncompliance;
    (b) Assess civil penalties; or
    (c) Initiate probationary or disqualification procedures from 
serving as an OCS operator.

Sec.  250.1928  What are my recordkeeping and documentation 
requirements?

    (a) Your SEMS program procedures must ensure that records and 
documents are maintained for a period of 6 years, except as provided 
below. You must document and keep all SEMS audits for 6 years and make 
them available to BSEE upon request. You must maintain a copy of all 
SEMS program documents at an onshore location.
    (b) For JSAs, the person in charge of the activity must document 
the results of the JSA in writing and must ensure that records are kept 
onsite for 30 days. You must retain these records for 2 years and make 
them available to BSEE upon request.
    (c) You must document and date all management of change provisions 
as specified in Sec.  250.1912. You must retain these records for 2 
years and make them available to BSEE upon request.
    (d) You must keep your injury/illness log for 2 years and make them 
available to BSEE upon request.
    (e) You must keep all evaluations completed on contractor's safety 
policies and procedures for 2 years and make them available to BSEE 
upon request.
    (f) You must keep all records in an orderly manner, readily 
identifiable, retrievable and legible, and include the date of any and 
all revisions.

Sec.  250.1929  What are my responsibilities for submitting OCS 
performance measure data?

    You must submit Form BSEE-0131 on an annual basis by March 31st. 
The form must be broken down quarterly, reporting the previous calendar 
year's data.

PART 251--GEOLOGICAL AND GEOPHYSICAL (G&G) EXPLORATIONS OF THE 
OUTER CONTINENTAL SHELF

Sec.
251.1 Definitions.
251.2 [Reserved]
251.3 Authority and applicability of this part.
251.4-251.6 [Reserved]
251.7 Test drilling activities under a permit.
251.8-251.14 [Reserved]
251.15 Authority for information collection.

    Authority: 31 U.S.C. 9701, 43 U.S.C. 1334.

Sec.  251.1  Definitions.

    Terms used in this part have the following meaning:
    Act means the Outer Continental Shelf Lands Act (OCSLA), as amended 
(43 U.S.C. 1331 et seq.).
    Analyzed geological information means data collected under a permit 
or a lease that have been analyzed. Analysis may include, but is not 
limited

[[Page 64599]]

to, identification of lithologic and fossil content, core analyses, 
laboratory analyses of physical and chemical properties, well logs or 
charts, results from formation fluid tests, and descriptions of 
hydrocarbon occurrences or hazardous conditions.
    Archaeological interest means capable of providing scientific or 
humanistic understanding of past human behavior, cultural adaptation, 
and related topics through the application of scientific or scholarly 
techniques, such as controlled observation, contextual measurements, 
controlled collection, analysis, interpretation, and explanation.
    Archaeological resources mean any material remains of human life or 
activities that are at least 50 years of age and of archaeological 
interest.
    Coastal environment means the physical, atmospheric, and biological 
components, conditions, and factors that interactively determine the 
productivity, state, condition, and quality of the terrestrial 
ecosystem from the shoreline inward to the boundaries of the coastal 
zone.
    Coastal Zone means the coastal waters (including the lands therein 
and thereunder) and the adjacent shorelands (including the waters 
therein and thereunder), strongly influenced by each other and in 
proximity to the shorelines of the several coastal States and extends 
seaward to the outer limit of the U.S. territorial sea.
    Coastal Zone Management Act means the Coastal Zone Management Act 
of 1972, as amended (16 U.S.C. 1451 et seq.).
    Data means facts, statistics, measurements, or samples that have 
not been analyzed, processed, or interpreted.
    Deep stratigraphic test means drilling that involves the 
penetration into the sea bottom of more than 500 feet (152 meters).
    Director means the Director of the Bureau of Safety and 
Environmental Enforcement, U.S. Department of the Interior, or a 
subordinate authorized to act on the Director's behalf.
    Exploration means the commercial search for oil, gas, and sulphur. 
Activities classified as exploration include, but are not limited to:
    (1) Geological and geophysical marine and airborne surveys where 
magnetic, gravity, seismic reflection, seismic refraction, gas 
sniffers, coring, or other systems are used to detect or imply the 
presence of oil, gas, or sulphur; and
    (2) Any drilling, whether on or off a geological structure.
    Geological and geophysical scientific research means any oil, gas, 
or sulphur related investigation conducted in the OCS for scientific 
and/or research purposes. Geological, geophysical, and geochemical data 
and information gathered and analyzed are made available to the public 
for inspection and reproduction at the earliest practicable time. The 
term does not include commercial geological or geophysical exploration 
or research.
    Geological exploration means exploration that uses geological and 
geochemical techniques (e.g., coring and test drilling, well logging, 
and bottom sampling) to produce data and information on oil, gas, and 
sulphur resources in support of possible exploration and development 
activities. The term does not include geological scientific research.
    Geological information means geological or geochemical data that 
have been analyzed, processed, or interpreted.
    Geophysical data means measurements that have not been processed or 
interpreted.
    Geophysical exploration means exploration that utilizes geophysical 
techniques (e.g., gravity, magnetic, electromagnetic, or seismic) to 
produce data and information on oil, gas, and sulphur resources in 
support of possible exploration and development activities. The term 
does not include geophysical scientific research.
    Geophysical information means geophysical data that have been 
processed or interpreted.
    Governor means the Governor of a State or the person or entity 
lawfully designated to exercise the powers granted to a Governor 
pursuant to the Act.
    Human environment means the physical, social, and economic 
components, conditions, and factors which interactively determine the 
state, condition, and quality of living conditions, employment, and 
health of those affected, directly or indirectly, by activities 
occurring on the OCS.
    Hydrocarbon occurrence means the direct or indirect detection 
during drilling operations of any liquid or gaseous hydrocarbons by 
examination of well cuttings, cores, gas detector readings, formation 
fluid tests, wireline logs, or by any other means. The term does not 
include background gas, minor accumulations of gas, or heavy oil 
residues on cuttings and cores.
    Interpreted geological information means knowledge, often in the 
form of schematic cross sections, 3-dimensional representations, and 
maps, developed by determining the geological significance of 
geological data and analyzed and processed geologic information.
    Interpreted geophysical information means knowledge, often in the 
form of seismic cross sections, 3-dimensional representations, and 
maps, developed by determining the geological significance of 
geophysical data and processed geophysical information.
    Lease means an agreement which is issued under section 8 or 
maintained under section 6 of the Act and which authorizes exploration 
for, and development and production of, minerals or the area covered by 
that authorization, whichever is required by the context.
    Lessee means a person who has entered into, or is the BOEM approved 
assignee of, a lease with the United States to explore for, develop, 
and produce the leased minerals. The term ``lessee'' also includes an 
owner of operating rights.
    Marine environment means the physical, atmospheric, and biological 
components, conditions, and factors that interactively determine the 
quality of the marine ecosystem in the coastal zone and in the OCS.
    Material remains mean physical evidence of human habitation, 
occupation, use, or activity, including the site, location, or context 
in which such evidence is situated.
    Minerals mean oil, gas, sulphur, geopressured-geothermal and 
associated resources, and all other minerals which are authorized by an 
Act of Congress to be produced from public lands as defined in section 
103 of the Federal Land Policy and Management Act of 1976 (43 U.S.C. 
1702).
    Notice means a written statement of intent to conduct geological or 
geophysical scientific research related to oil, gas, and sulphur in the 
OCS other than under a permit.
    Oil, gas, and sulphur mean oil, gas, sulphur, geopressured-
geothermal, and associated resources.
    Outer Continental Shelf (OCS) means all submerged lands lying 
seaward and outside the area of lands beneath navigable waters as 
defined in section 2 of the Submerged Lands Act (43 U.S.C. 1301), and 
of which the subsoil and seabed appertain to the United States and are 
subject to its jurisdiction and control.
    Permit means the contract or agreement, other than a lease, issued 
pursuant to this part, under which a person acquires the right to 
conduct on the OCS, in accordance with appropriate statutes, 
regulations, and stipulations:
    (1) Geological exploration for mineral resources;
    (2) Geophysical exploration for mineral resources;

[[Page 64600]]

    (3) Geological scientific research; or
    (4) Geophysical scientific research.
    Permittee means the person authorized by a permit issued pursuant 
to this part to conduct activities on the OCS.
    Person means a citizen or national of the United States; an alien 
lawfully admitted for permanent residence in the United States as 
defined in section 8 U.S.C. 1101(a)(20); a private, public, or 
municipal corporation organized under the laws of the United States or 
of any State or territory thereof; and associations of such citizens, 
nationals, resident aliens, or private, public, or municipal 
corporations, States, or political subdivisions of States or anyone 
operating in a manner provided for by treaty or other applicable 
international agreements. The term does not include Federal agencies.
    Processed geological or geophysical information means data 
collected under a permit and later processed or reprocessed. Processing 
involves changing the form of data so as to facilitate interpretation. 
Processing operations may include, but are not limited to, applying 
corrections for known perturbing causes, rearranging or filtering data, 
and combining or transforming data elements. Reprocessing is the 
additional processing other than ordinary processing used in the 
general course of evaluation. Reprocessing operations may include 
varying identified parameters for the detailed study of a specific 
problem area. Reprocessing may occur several years after the original 
processing date. Reprocessing is determined to be completed on the date 
that the reprocessed information is first available in a useable format 
for in-house interpretation by BOEM or the permittee, or becomes first 
available to third parties via sale, trade, license agreement, or other 
means.
    Secretary means the Secretary of the Interior or a subordinate 
authorized to act on the Secretary's behalf.
    Shallow test drilling means drilling into the sea bottom to depths 
less than those specified in the definition of a deep stratigraphic 
test.
    Significant archaeological resource means those archaeological 
resources that meet the criteria of significance for eligibility to the 
National Register of Historic Places as defined in 36 CFR 60.4.
    Third Party means any person other than the permittee or a 
representative of the United States, including all persons who obtain 
data or information acquired under a permit from the permittee, or from 
another third party, by sale, trade, license agreement, or other means.
    Violation means a failure to comply with any provision of the Act, 
or a provision of a regulation or order issued under the Act, or any 
provision of a lease, license, or permit issued under the Act.
    You means a person who applies for and/or obtains a permit, or 
files a Notice to conduct geological or geophysical exploration or 
scientific research related to oil, gas, and sulphur in the OCS.

Sec.  251.2  [Reserved]

Sec.  251.3  Authority and applicability of this part.

    BSEE authorizes you to conduct exploration or scientific research 
activities under this part in accordance with the Act, the regulations 
in this part, orders of the Director/Regional Director, and other 
applicable statutes, regulations, and amendments.
    (a) This part does not apply to G&G exploration conducted by or on 
behalf of the lessee on a lease in the OCS. Refer to 30 CFR part 550 if 
you plan to conduct G&G activities related to oil, gas, or sulphur 
under terms of a lease.
    (b) Federal agencies are exempt from the regulations in this part.
    (c) G&G exploration or G&G scientific research related to minerals 
other than oil, gas, and sulphur is covered by regulations at 30 CFR 
part 580.

Sec. Sec.  251.4-251.6  [Reserved]

Sec.  251.7  Test drilling activities under a permit.

    (a) [Reserved]
    (b) Deep stratigraphic tests. You must submit to the appropriate 
BOEM or BSEE Regional Director, at the address in 30 CFR 551.5(d) for 
BOEM or 30 CFR 254.7 for BSEE, a drilling plan (submitted to BOEM), an 
environmental report (submitted to BOEM), an Application for Permit to 
Drill (Form BSEE-0123) (submitted to BSEE), and a Supplemental APD 
Information Sheet (Form BSEE-0123S) (submitted to BSEE) as follows:
    (1) Drilling plan. The drilling plan must include:
    (i) The proposed type, sequence, and timetable of drilling 
activities;
    (ii) A description of your drilling rig, indicating the important 
features with special attention to safety, pollution prevention, oil-
spill containment and cleanup plans, and onshore disposal procedures;
    (iii) The location of each deep stratigraphic test you will 
conduct, including the location of the surface and projected bottomhole 
of the borehole;
    (iv) The types of geological and geophysical survey instruments you 
will use before and during drilling;
    (v) Seismic, bathymetric, sidescan sonar, magnetometer, or other 
geophysical data and information sufficient to evaluate seafloor 
characteristics, shallow geologic hazards, and structural detail across 
and in the vicinity of the proposed test to the total depth of the 
proposed test well; and
    (vi) Other relevant data and information that the BOEM Regional 
Director requires.
    (2) Environmental report. The environmental report must include all 
of the following material:
    (i) A summary with data and information available at the time you 
submitted the related drilling plan. BOEM will consider site-specific 
data and information developed since the most recent environmental 
impact statement or other environmental impact analysis in the 
immediate area. The summary must meet the following requirements:
    (A) You must concentrate on the issues specific to the site(s) of 
drilling activity. However, you only need to summarize data and 
information discussed in any environmental reports, analyses, or impact 
statements prepared for the geographic area of the drilling activity.
    (B) You must list referenced material. Include brief descriptions 
and a statement of where the material is available for inspection.
    (C) You must refer only to data that are available to BOEM.
    (ii) Details about your project such as:
    (A) A list and description of new or unusual technologies;
    (B) The location of travel routes for supplies and personnel;
    (C) The kinds and approximate levels of energy sources;
    (D) The environmental monitoring systems; and
    (E) Suitable maps and diagrams showing details of the proposed 
project layout.
    (iii) A description of the existing environment. For this section, 
you must include the following information on the area:
    (A) Geology;
    (B) Physical oceanography;
    (C) Other uses of the area;
    (D) Flora and fauna;
    (E) Existing environmental monitoring systems; and
    (F) Other unusual or unique characteristics that may affect or be 
affected by the drilling activities.
    (iv) A description of the probable impacts of the proposed action 
on the environment and the measures you propose for mitigating these 
impacts.

[[Page 64601]]

    (v) A description of any unavoidable or irreversible adverse 
effects on the environment that could occur.
    (vi) Other relevant data that the BOEM Regional Director requires.
    (3) Copies for coastal States. You must submit copies of the 
drilling plan and environmental report to the BOEM Regional Director 
for transmittal to the Governor of each affected coastal State and the 
coastal zone management agency of each affected coastal State that has 
an approved program under the Coastal Zone Management Act. (The BOEM 
Regional Director will make the drilling plan and environmental report 
available to appropriate Federal agencies and the public according to 
the Department of the Interior's policies and procedures).
    (4) Certification of coastal zone management program consistency 
and State concurrence. When required under an approved coastal zone 
management program of an affected State, your drilling plan must 
include a certification that the proposed activities described in the 
plan comply with enforceable policies of, and will be conducted in a 
manner consistent with such State's program. The BOEM Regional Director 
may not approve any of the activities described in the drilling plan 
unless the State concurs with the consistency certification or the 
Secretary of Commerce makes the finding authorized by section 
307(c)(3)(B)(iii) of the Coastal Zone Management Act.
    (5) Protecting archaeological resources. If the BOEM Regional 
Director believes that an archaeological resource may exist in the area 
that may be affected by drilling, the BOEM Regional Director will 
notify you of the need to prepare an archaeological report under 30 CFR 
551.7(b)(5).
    (i) If the evidence suggests that an archaeological resource may be 
present, you must:
    (A) Locate the site of the drilling so as to not adversely affect 
the area where the archaeological resources may be, or
    (B) Establish to the satisfaction of the BOEM Regional Director 
that an archaeological resource does not exist or will not be adversely 
affected by drilling. This must be done by further archaeological 
investigation, conducted by an archaeologist and a geophysicist, using 
survey equipment and techniques deemed necessary by the Regional 
Director. A report on the investigation must be submitted to the BOEM 
Regional Director for review.
    (ii) If the BOEM Regional Director determines that an 
archaeological resource is likely to be present in the area that may be 
affected by drilling, and may be adversely affected by drilling, the 
BOEM Regional Director will notify you immediately. You must take no 
action that may adversely affect the archaeological resource unless 
further investigations determine that the resource is not 
archaeologically significant.
    (iii) If you discover any archaeological resource while drilling, 
you must immediately halt drilling and report the discovery to the BOEM 
Regional Director. If investigations determine that the resource is 
significant, the BOEM Regional Director will inform you how to protect 
it.
    (6) Application for permit to drill (APD). Before commencing deep 
stratigraphic test drilling activities under an approved drilling plan, 
you must submit an APD and a Supplemental APD Information Sheet (Forms 
BSEE-0123 and BSEE-0123S) and receive approval. You must comply with 
all regulations relating to drilling operations in 30 CFR part 250.
    (7) Revising an approved drilling plan. Before you revise an 
approved drilling plan, you must obtain the BOEM Regional Director's 
approval.
    (8) After drilling. When you complete the test activities, you must 
permanently plug and abandon the boreholes of all deep stratigraphic 
tests in compliance with 30 CFR part 250. If the tract on which you 
conducted a deep stratigraphic test is leased to another party for 
exploration and development, and if the lessee has not disturbed the 
borehole, BSEE will hold you and not the lessee responsible for 
problems associated with the test hole.
    (9) Deadline for completing a deep stratigraphic test. If your deep 
stratigraphic test well is within 50 geographic miles of a tract that 
BOEM has identified for a future lease sale, as listed on the currently 
approved OCS leasing schedule, you must complete all drilling 
activities and submit the data and information to the BOEM Regional 
Director at least 60 days before the first day of the month in which 
BOEM schedules the lease sale. However, the BOEM Regional Director may 
extend your permit duration to allow you to complete drilling 
activities and submit data and information if the extension is in the 
National interest.
    (c) [Reserved]
    (d) [Reserved]

Sec.  251.8-251.14  [Reserved]

Sec.  251.15  Authority for information collection.

    The Office of Management and Budget has approved the information 
collection requirements in this part under 44 U.S.C. 3501 et seq. and 
assigned OMB control number 1010-0141 as it pertains to Application for 
Permit to Drill (APD, Form BSEE-0123), and Supplemental APD Information 
Sheet (Form BSEE-0123S). The title of this information collection is 
``30 CFR part 250, subpart D, ``Oil and Gas Drilling Operations.''

PART 252--OUTER CONTINENTAL SHELF (OCS) OIL AND GAS INFORMATION 
PROGRAM

Sec
252.1 Purpose.
252.2 Definitions.
252.3 Oil and gas data and information to be provided for use in the 
OCS Oil and Gas Information Program.
252.4 Summary Report to affected States.
252.5 Information to be made available to affected States.
252.6 Freedom of Information Act requirements.
252.7 Privileged and proprietary data and information to be made 
available to affected States.

    Authority: OCS Lands Act, 43 U.S.C. 1331 et seq., as amended, 92 
Stat. 629; Freedom of Information Act, 5 U.S.C. 552; Sec.  252.3 
also issued under Pub. L. 99-190 making continuing appropriations 
for Fiscal Year 1986, and for other purposes.

Sec.  252.1  Purpose.

    The purpose of this part is to implement the provisions of section 
26 of the Act (43 U.S.C. 1352). This part supplements the procedures 
and requirements contained in 30 CFR parts 250, 251, 550, and 551 and 
provides procedures and requirements for the submission of oil and gas 
data and information resulting from exploration, development, and 
production operations on the Outer Continental Shelf (OCS) to the 
Director, Bureau of Safety and Environmental Enforcement (BSEE). In 
addition, this part establishes procedures for the Director to make 
available certain information to the Governors of affected States and, 
upon request, to the executives of affected local governments in 
accordance with the provisions of the Freedom of Information Act and 
the Act.

Sec.  252.2  Definitions.

    When used in the regulations in this part, the following terms 
shall have the following meanings:
    Act refers to the Outer Continental Shelf Lands Act, as amended (43 
U.S.C. 1331 et seq.).
    Affected local government means the principal governing body of a 
locality which is in an affected State and is identified by the 
Governor of that State as a locality which will be significantly 
affected by oil and gas activities on the OCS.

[[Page 64602]]

    Affected State means, with respect to any program, plan, lease 
sale, or other activity, proposed, conducted, or approved pursuant to 
the provisions of the Act, any State:
    (1) The laws of which are declared, pursuant to section 4(a)(2)(A) 
of the Act, to be the law of the United States for the portion of the 
OCS on which such activity is, or is proposed to be, conducted;
    (2) Which is, or is proposed to be, directly connected by 
transportation facilities to any artificial island or installations and 
other devices permanently, or temporarily attached to the seabed;
    (3) Which is receiving, or in accordance with the proposed activity 
will receive, oil for processing, refining, or transshipment which was 
extracted from the OCS and transported directly to such State by means 
of vessels or by a combination of means including vessels;
    (4) Which is designated by the Director as a State in which there 
is a substantial probability of significant impact on or damage to the 
coastal, marine, or human environment, or a State in which there will 
be significant changes in the social, governmental, or economic 
infrastructure, resulting from the exploration, development, and 
production of oil and gas anywhere on the OCS; or
    (5) In which the Director finds that because of such activity there 
is, or will be, a significant risk of serious damage, due to factors 
such as prevailing winds and currents, to the marine or coastal 
environment in the event of any oilspill, blowout, or release of oil or 
gas from vessels, pipelines, or other transshipment facilities.
    Analyzed geological information means data collected under a permit 
or a lease which have been analyzed. Analysis may include, but is not 
limited to, identification of lithologic and fossil content, core 
analyses, laboratory analyses of physical and chemical properties, logs 
or charts of electrical, radioactive, sonic, and other well logs, and 
descriptions of hydrocarbon shows or hazardous conditions.
    Area adjacent to a State means all of that portion of the OCS 
included within a planning area if such planning area is bordered by 
that State. The portion of the OCS in the Navarin Basin Planning Area 
is deemed to be adjacent to the State of Alaska. The States of New York 
and Rhode Island are deemed to be adjacent to both the Mid-Atlantic 
Planning Area and the North Atlantic Planning Area.
    Data means facts and statistics or samples which have not been 
analyzed or processed.
    Development means those activities which take place following 
discovery of oil or natural gas in paying quantities, including 
geophysical activity, drilling, platform construction, and operation of 
all onshore support facilities, and which are for the purpose of 
ultimately producing the oil and gas discovered.
    Director means the Director of the Bureau of Safety and 
Environmental Enforcement (BSEE) of the U.S. Department of the Interior 
or a designee of the Director.
    Exploration means the process of searching for oil and natural gas, 
including:
    (1) Geophysical surveys where magnetic, gravity, seismic, or other 
systems are used to detect or imply the presence of such oil or natural 
gas, and
    (2) Any drilling, whether on or off known geological structures, 
including the drilling of a well in which a discovery of oil or natural 
gas in paying quantities is made and the drilling of any additional 
delineation well after such discovery which is needed to delineate any 
reservoir and to enable the lessee to determine whether to proceed with 
development and production.
    Governor means the Governor of a State, or the person or entity 
designated by, or pursuant to, State law to exercise the powers granted 
to a Governor pursuant to the Act.
    Information, when used without a qualifying adjective, includes 
analyzed geological information, processed geophysical information, 
interpreted geological information, and interpreted geophysical 
information.
    Interpreted geological information means knowledge, often in the 
form of schematic cross sections and maps, developed by determining the 
geological significance of data and analyzed geological information.
    Interpreted geophysical information means knowledge, often in the 
form of schematic cross sections and maps, developed by determining the 
geological significance of geophysical data and processed geophysical 
information.
    Lease means any form of authorization which is issued under section 
8 or maintained under section 6 of the Act and which authorizes 
exploration for, and development and production of, oil or natural gas, 
or the land covered by such authorization, whichever is required by the 
context.
    Lessee means the party authorized by a lease, or an approved 
assignment thereof, to explore for and develop and produce the leased 
deposits in accordance with the regulations in 30 CFR part 550, 
including all parties holding such authority by or through the lessee.
    Outer Continental Shelf (OCS) means all submerged lands which lie 
seaward and outside of the area of lands beneath navigable waters as 
defined in the Submerged Lands Act (67 Stat. 29) and of which the 
subsoil and seabed appertain to the United States and are subject to 
its jurisdiction and control.
    Permittee means the party authorized by a permit issued pursuant to 
30 CFR parts 251 and 551 to conduct activities on the OCS.
    Processed geophysical information means data collected under a 
permit or a lease which have been processed. Processing involves 
changing the form of data so as to facilitate interpretation. 
Processsing operations may include, but are not limited to, applying 
corrections for known perturbing causes, rearranging or filtering data, 
and combining or transforming data elements.
    Production means those activities which take place after the 
successful completion of any means for the removal of oil or natural 
gas, including such removal, field operations, transfer of oil or 
natural gas to shore, operation monitoring, maintenance, and workover 
drilling.
    Secretary means the Secretary of the Interior or a designee of the 
Secretary.

Sec.  252.3  Oil and gas data and information to be provided for use in 
the OCS Oil and Gas Information Program.

    (a) Any permittee or lessee engaging in the activities of 
exploration for, or development and production of, oil and gas on the 
OCS shall provide the Director access to all data and information 
obtained or developed as a result of such activities, including 
geological data, geophysical data, analyzed geological information, 
processed and reprocessed geophysical information, interpreted 
geophysical information, and interpreted geological information. Copies 
of these data and information and any interpretation of these data and 
information shall be provided to the Director upon request. No 
permittee or lessee submitting an interpretation of data or 
information, where such interpretation has been submitted in good 
faith, shall be held responsible for any consequence of the use of or 
reliance upon such interpretation.
    (b)(1) Whenever a lessee or permittee provides any data or 
information, at the request of the Director and specifically for use in 
the OCS Oil and Gas Information Program in a form and manner of 
processing which is utilized

[[Page 64603]]

by the lessee or permittee in the normal conduct of business, the 
Director shall pay the reasonable cost of reproducing the data and 
information if the lessee or permittee requests reimbursement. The cost 
shall be computed and paid in accordance with the applicable provisions 
of paragraph (e)(1) of this section.
    (2) Whenever a lessee or permittee provides any data or 
information, at the request of the Director and specifically for use in 
the OCS Oil and Gas Information Program, in a form and manner of 
processing not normally utilized by the lessee or permittee in the 
normal conduct of business, the Director shall pay the lessee or 
permittee, if the lessee or permittee requests reimbursement, the 
reasonable cost of processing and reproducing the requested data and 
information. The cost is to be computed and paid in accordance with the 
applicable provisions of paragraph (e)(2) of this section.
    (c) Data or information requested by the Director shall be provided 
as soon as practicable, but not later than 30 days following receipt of 
the Director's request, unless, for good reason, the Director 
authorizes a longer time period for the submission of the requested 
data or information.
    (d) The Director reserves the right to disclose any data or 
information acquired from a lessee or permittee to an independent 
contractor or agent for the purpose of reproducing, processing, 
reprocessing, or interpreting such data or information. When 
practicable, the Director shall notify the lessee(s) or permittee(s) 
who provided the data or information of the intent to disclose the data 
or information to an independent contractor or agent. The Director's 
notice of intent will afford the permittee(s) or lessee(s) a period of 
not less than 5 working days within which to comment on the intended 
action. When the Director so notifies a lessee or permittee of the 
intent to disclose data or information to an independent contractor or 
agent, all other owners of such data or information shall be deemed to 
have been notified of the Director's intent. Prior to any such 
disclosure, the contractor or agent shall be required to execute a 
written commitment not to disclose any data or information to anyone 
without the express consent of the Director, and not to make any 
disclosure or use of the data or information other than that provided 
in the contract. Contracts between BSEE and independent contractors 
shall be available to the lessee(s) or permittee(s) for inspection. In 
the event of any unauthorized use or disclosure of data or information 
by the contractor or agent, or by an employee thereof, the responsible 
contractor or agent or employee thereof shall be liable for penalties 
pursuant to section 24 of the Act.
    (e)(1) After delivery of data or information in accordance with 
paragraph (b)(1) of this section and upon receipt of a request for 
reimbursement and a determination by the Director that the requested 
reimbursement is proper, the lessee or permittee shall be reimbursed 
for the cost of reproducing the data or information at the lessee's or 
permittee's lowest rate or at the lowest commercial rate established in 
the area, whichever is less. Requests for reimbursement must be made 
within 60 days of the delivery date of the data or information 
requested under paragraph (b)(1) of this section.
    (2) After delivery of data or information in accordance with 
paragraph (b)(3) of this section, and upon receipt of a request for 
reimbursement and a determination by the Director that the requested 
reimbursement is proper, the lessee or permittee shall be reimbursed 
for the cost of processing or reprocessing and of reproducing the 
requested data or information. Requests for reimbursement must be made 
within 60 days of the delivery date of the data or information and 
shall be for only the costs attributable to processing or reprocessing 
and reproducing, as distinguished from the costs of data acquisition.
    (3) Requests for reimbursement are to contain a breakdown of costs 
in sufficient detail to allow separation of reproduction, processing, 
and reprocessing costs from acquisition and other costs.
    (f) Each Federal Department or Agency shall provide the Director 
with any data which it has obtained pursuant to section 11 of the Act 
and any other information which may be necessary or useful to assist 
the Director in carrying out the provisions of the Act.

Sec.  252.4  Summary Report to affected States.

    (a) The Director, as soon as practicable after analysis, 
interpretation, and compilation of oil and gas data and information 
developed by BSEE or furnished by lessees, permittees, or other 
government agencies, shall make available to affected States and, upon 
request, to the executive of any affected local government, a Summary 
Report of data and information designed to assist them in planning for 
the onshore impacts of potential OCS oil and gas development and 
production. The Director shall consult with affected States and other 
interested parties to define the nature, scope, content, and timing of 
the Summary Report. The Director may consult with affected States and 
other interested parties regarding subsequent revisions in the 
definition of the nature, scope, content, and timing of the Summary 
Report. The Summary Report shall not contain data or information which 
the Director determines is exempt from disclosure in accordance with 
this part. The Summary Report shall not contain data or information the 
release of which the Director determines would unduly damage the 
competitive position of the lessee or permittee who provided the data 
or information which the Director has processed, analyzed, or 
interpreted during the development of the Summary Report. The Summary 
Report shall include:
    (1) Estimates of oil and gas reserves; estimates of the oil and gas 
resources that may be found within areas which the Secretary has leased 
or plans to offer for lease; and when available, projected rates and 
volumes of oil and gas to be produced from leased areas;
    (2) Magnitude of the approximate projections and timing of 
development, if and when oil or gas, or both, is discovered;
    (3) Methods of transportation to be used, including vessels and 
pipelines and approximate location of routes to be followed; and
    (4) General location and nature of near-shore and onshore 
facilities expected to be utilized.
    (b) When the Director determines that significant changes have 
occurred in the information contained in a Summary Report, the Director 
shall prepare and make available the new or revised information to each 
affected State, and, upon request, to the executive of any affected 
local government.

Sec.  252.5  Information to be made available to affected States.

    (a) The BOEM Director shall prepare an index of OCS information 
(see 30 CFR 556.10). The index shall list all relevant actual or 
proposed programs, plans, reports, environmental impact statements, 
nominations information, environmental study reports, lease sale 
information, and any similar type of relevant information, including 
modifications, comments, and revisions prepared or directly obtained by 
the Director under the Act. The index shall be sent to affected States 
and, upon request, to any affected local government. The public shall 
be informed of the availability of the index.

[[Page 64604]]

    (b) Upon request, the Director shall transmit to affected States, 
affected local governments, and the public a copy of any information 
listed in the index which is subject to the control of BOEM, in 
accordance with the requirements and subject to the limitations of the 
Freedom of Information Act (5 U.S.C.552) and implementing regulations. 
The Director shall not transmit or make available any information which 
he determines is exempt from disclosure in accordance with this part.

Sec.  252.6  Freedom of Information Act requirements.

    (a) The Director shall make data and information available in 
accordance with the requirements and subject to the limitations of the 
Freedom of Information Act (5 U.S.C. 552), the regulations contained in 
43 CFR part 2 (Records and Testimony), the requirements of the Act, and 
the regulations contained in 30 CFR parts 250 and 550 (Oil and Gas and 
Sulphur Operations in the Outer Continental Shelf) and 30 CFR parts 251 
and 551 (Geological and Geophysical Explorations of the Outer 
Continental Shelf).
    (b) Except as provided in Sec.  252.7 or in 30 CFR parts 250, 251, 
550, and 551, no data or information determined by the Director to be 
exempt from public disclosure under paragraph (a) of this section shall 
be provided to any affected State or be made available to the executive 
of any affected local government or to the public unless the lessee, or 
the permittee and all persons to whom such permittee has sold such data 
or information under promise of confidentiality, agree to such action.

Sec.  252.7  Privileged and proprietary data and information to be made 
available to affected States.

    (a)(1) The Governor of any affected State may designate an 
appropriate State official to inspect, at a regional location which the 
Director shall designate, any privileged or proprietary data or 
information received by the Director regarding any activity in an area 
adjacent to such State, except that no such inspection shall take place 
prior to the sale of a lease covering the area in which such activity 
was conducted.
    (2)(i) Except as provided for in 30 CFR 250.197, 30 CFR 550.197, 
and 30 CFR 551.14, no privileged or proprietary data or information 
will be transmitted to any affected State unless the lessee who 
provided the privileged or proprietary data or information agrees in 
writing to the transmittal of the data or information.
    (ii) Except as provided for in 30 CFR 250.197, 30 CFR 550.197, and 
30 CFR 551.14, no privileged or proprietary data or information will be 
transmitted to any affected State unless the permittee and all persons 
to whom the permittee has sold the data or information under promise of 
confidentiality agree in writing to the transmittal of the data or 
information.
    (3) Knowledge obtained by a State official who inspects data or 
information under paragraph (a)(1) or who receives data or information 
under paragraph (a)(2) of this section shall be subject to the 
requirements and limitations of the Freedom of Information Act (5 
U.S.C. 552), the regulations contained in 43 CFR part 2 (Records and 
Testimony), the Act (92 Stat. 629), the regulations contained in 30 CFR 
parts 250 and 550 (Oil and Gas and Sulphur Operations in the Outer 
Continental Shelf), the regulations contained in 30 CFR parts 251 and 
551 (Geological and Geophysical Explorations of the Outer Continental 
Shelf), and the regulations contained in 30 CFR parts 252 and 552 
(Outer Continental Shelf Oil and Gas Information Program).
    (4) Prior to the transmittal of any privileged or proprietary data 
or information to any State, or the grant of access to a State official 
to such data or information, the Secretary shall enter into a written 
agreement with the Governor of the State in accordance with section 
26(e) of the Act (43 U.S.C. 1352). In that agreement the State shall 
agree, as a condition precedent to receiving or being granted access to 
such data or information to: (i) Protect and maintain the 
confidentiality of privileged or proprietary data and information in 
accordance with the laws and regulations listed in paragraph (a)(3) of 
this section;
    (ii) Waive the defenses as set forth in paragraph (b)(2) of this 
section; and
    (iii) Hold the United States harmless from any violations of the 
agreement to protect the confidentiality of privileged or proprietary 
data or information by the State or its employees or contractors.
    (b)(1) Whenever any employee of the Federal Government or of any 
State reveals in violation of the Act or of the provisions of the 
regulations implementing the Act, privileged or proprietary data or 
information obtained pursuant to the regulations in this chapter, the 
lessee or permittee who supplied such information to the Director or 
any other Federal official, and any person to whom such lessee or 
permittee has sold such data or information under the promise of 
confidentiality, may commence a civil action for damages in the 
appropriate district court of the United States against the Federal 
Government or such State, as the case may be. Any Federal or State 
employee who is found guilty of failure to comply with any of the 
requirements of this section shall be subject to the penalties 
described in section 24 of the Act (43 U.S.C. 1350).
    (2) In any action commenced against the Federal Government or a 
State pursuant to paragraph (b)(1) of this section, the Federal 
Government or such State, as the case may be, may not raise as a 
defense any claim of sovereign immunity, or any claim that the employee 
who revealed the privileged or proprietary data or information which is 
the basis of such suit was acting outside the scope of the person's 
employment in revealing such data or information.
    (c) If the Director finds that any State cannot or does not comply 
with the conditions described in the agreement entered into pursuant to 
paragraph (a)(4) of this section, the Director shall thereafter 
withhold transmittal and deny access for inspection of privileged or 
proprietary data or information to such State until the Director finds 
that such State can and will comply with those conditions.

PART 253--[RESERVED]

PART 254--OIL-SPILL RESPONSE REQUIREMENTS FOR FACILITIES LOCATED 
SEAWARD OF THE COAST LINE

Subpart A--General
Sec.
254.1 Who must submit a spill-response plan?
254.2 When must I submit a response plan?
254.3 May I cover more than one facility in my response plan?
254.4 May I reference other documents in my response plan?
254.5 General response plan requirements.
254.6 Definitions.
254.7 How do I submit my response plan to the BSEE?
254.8 May I appeal decisions under this part?
254.9 Authority for information collection.
Subpart B--Oil-Spill Response Plans for Outer Continental Shelf 
Facilities
254.20 Purpose.
254.21 How must I format my response plan?
254.22 What information must I include in the ``Introduction and 
plan contents'' section?
254.23 What information must I include in the ``Emergency response 
action plan'' section?
254.24 What information must I include in the ``Equipment 
inventory'' appendix?

[[Page 64605]]

254.25 What information must I include in the ``Contractual 
agreements'' appendix?
254.26 What information must I include in the ``Worst case discharge 
scenario'' appendix?
254.27 What information must I include in the ``Dispersant use 
plan'' appendix?
254.28 What information must I include in the ``In situ burning 
plan'' appendix?
254.29 What information must I include in the ``Training and 
drills'' appendix?
254.30 When must I revise my response plan?
Subpart C--Related Requirements for Outer Continental Shelf Facilities
254.40 Records.
254.41 Training your response personnel.
254.42 Exercises for your response personnel and equipment.
254.43 Maintenance and periodic inspection of response equipment.
254.44 Calculating response equipment effective daily recovery 
capacities.
254.45 Verifying the capabilities of your response equipment.
254.46 Whom do I notify if an oil spill occurs?
254.47 Determining the volume of oil of your worst case discharge 
scenario.
Subpart D--Oil-Spill Response Requirements for Facilities Located in 
State Waters Seaward of the Coast Line
254.50 Spill response plans for facilities located in State waters 
seaward of the coast line.
254.51 Modifying an existing OCS response plan.
254.52 Following the format for an OCS response plan.
254.53 Submitting a response plan developed under State 
requirements.
254.54 Spill prevention for facilities located in State waters 
seaward of the coast line.

    Authority: 33 U.S.C. 1321.

Subpart A--General

Sec.  254.1  Who must submit a spill-response plan?

    (a) If you are the owner or operator of an oil handling, storage, 
or transportation facility, and it is located seaward of the coast 
line, you must submit a spill-response plan to BSEE for approval. Your 
spill-response plan must demonstrate that you can respond quickly and 
effectively whenever oil is discharged from your facility. Refer to 
Sec.  254.6 for the definitions of ``oil,'' ``facility,'' and ``coast 
line'' if you have any doubts about whether to submit a plan.
    (b) You must maintain a current response plan for an abandoned 
facility until you physically remove or dismantle the facility or until 
the Regional Supervisor notifies you in writing that a plan is no 
longer required.
    (c) Owners or operators of offshore pipelines carrying essentially 
dry gas do not need to submit a plan. You must, however, submit a plan 
for a pipeline that carries:
    (1) Oil;
    (2) Condensate that has been injected into the pipeline; or
    (3) Gas and naturally occurring condensate.
    (d) If you are in doubt as to whether you must submit a plan for an 
offshore facility or pipeline, you should check with the Regional 
Supervisor.
    (e) If your facility is located landward of the coast line, but you 
believe your facility is sufficiently similar to OCS facilities that it 
should be regulated by BSEE, you may contact the Regional Supervisor, 
offer to accept BSEE jurisdiction over your facility, and request that 
BSEE seek from the agency with jurisdiction over your facility a 
relinquishment of that jurisdiction.

Sec.  254.2  When must I submit a response plan?

    (a) You must submit, and BSEE must approve, a response plan that 
covers each facility located seaward of the coast line before you may 
use that facility. To continue operations, you must operate the 
facility in compliance with the plan.
    (b) Despite the provisions of paragraph (a) of this section, you 
may operate your facility after you submit your plan while BSEE reviews 
it for approval. To operate a facility without an approved plan, you 
must certify in writing to the Regional Supervisor that you have the 
capability to respond, to the maximum extent practicable, to a worst 
case discharge or a substantial threat of such a discharge. The 
certification must show that you have ensured by contract, or other 
means approved by the Regional Supervisor, the availability of private 
personnel and equipment necessary to respond to the discharge. 
Verification from the organization(s) providing the personnel and 
equipment must accompany the certification. BSEE will not allow you to 
operate a facility for more than 2 years without an approved plan.
    (c) If you have a plan that BSEE already approved, you are not 
required to immediately rewrite the plan to comply with this part. You 
must, however, submit the information this regulation requires when 
submitting your first plan revision (see Sec.  254.30) after the 
effective date of this rule. The Regional Supervisor may extend this 
deadline upon request.

Sec.  254.3  May I cover more than one facility in my response plan?

    (a) Your response plan may be for a single lease or facility or a 
group of leases or facilities. All the leases or facilities in your 
plan must have the same owner or operator (including affiliates) and 
must be located in the same BSEE Region (see definition of Regional 
Response Plan in Sec.  254.6).
    (b) Regional Response Plans must address all the elements required 
for a response plan in Subpart B, Oil Spill Response Plans for Outer 
Continental Shelf Facilities, or Subpart D, Oil Spill Response 
Requirements for Facilities Located in State Waters Seaward of the 
Coast Line, as appropriate.
    (c) When developing a Regional Response Plan, you may group leases 
or facilities subject to the approval of the Regional Supervisor for 
the purposes of:
    (1) Calculating response times;
    (2) Determining quantities of response equipment;
    (3) Conducting oil-spill trajectory analyses;
    (4) Determining worst case discharge scenarios; and
    (5) Identifying areas of special economic and environmental 
importance that may be impacted and the strategies for their 
protection.
    (d) The Regional Supervisor may specify how to address the elements 
of a Regional Response Plan. The Regional Supervisor also may require 
that Regional Response Plans contain additional information if 
necessary for compliance with appropriate laws and regulations.

Sec.  254.4  May I reference other documents in my response plan?

    You may reference information contained in other readily accessible 
documents in your response plan. Examples of documents that you may 
reference are the National Contingency Plan (NCP), Area Contingency 
Plan (ACP), BSEE or BOEM environmental documents, and Oil Spill Removal 
Organization (OSRO) documents that are readily accessible to the 
Regional Supervisor. You must ensure that the Regional Supervisor 
possesses or is provided with copies of all OSRO documents you 
reference. You should contact the Regional Supervisor if you want to 
know whether a reference is acceptable.

Sec.  254.5  General response plan requirements.

    (a) The response plan must provide for response to an oil spill 
from the facility. You must immediately carry out the provisions of the 
plan whenever there is a release of oil from the facility. You must 
also carry out the training, equipment testing, and periodic drills 
described in the plan, and these measures must be sufficient to ensure 
the safety of the facility and to mitigate

[[Page 64606]]

or prevent a discharge or a substantial threat of a discharge.
    (b) The plan must be consistent with the National Contingency Plan 
and the appropriate Area Contingency Plan(s).
    (c) Nothing in this part relieves you from taking all appropriate 
actions necessary to immediately abate the source of a spill and remove 
any spills of oil.
    (d) In addition to the requirements listed in this part, you must 
provide any other information the Regional Supervisor requires for 
compliance with appropriate laws and regulations.

Sec.  254.6  Definitions.

    For the purposes of this part:
    Adverse weather conditions mean weather conditions found in the 
operating area that make it difficult for response equipment and 
personnel to clean up or remove spilled oil or hazardous substances. 
These include, but are not limited to: Fog, inhospitable water and air 
temperatures, wind, sea ice, current, and sea states. It does not refer 
to conditions such as a hurricane, under which it would be dangerous or 
impossible to respond to a spill.
    Area Contingency Plan means an Area Contingency Plan prepared and 
published under section 311(j) of the Federal Water Pollution Control 
Act (FWPCA).
    Coast line means the line of ordinary low water along that portion 
of the coast which is in direct contact with the open sea and the line 
marking the seaward limit of inland waters.
    Discharge means any emission (other than natural seepage), 
intentional or unintentional, and includes, but is not limited to, 
spilling, leaking, pumping, pouring, emitting, emptying, or dumping.
    District Manager means the BSEE officer with authority and 
responsibility for a district within a BSEE Region.
    Facility means any structure, group of structures, equipment, or 
device (other than a vessel) which is used for one or more of the 
following purposes: Exploring for, drilling for, producing, storing, 
handling, transferring, processing, or transporting oil. The term 
excludes deep-water ports and their associated pipelines as defined by 
the Deepwater Port Act of 1974, but includes other pipelines used for 
one or more of these purposes. A mobile offshore drilling unit is 
classified as a facility when engaged in drilling or downhole 
operations.
    Maximum extent practicable means within the limitations of 
available technology, as well as the physical limitations of personnel, 
when responding to a worst case discharge in adverse weather 
conditions.
    National Contingency Plan means the National Oil and Hazardous 
Substances Pollution Contingency Plan prepared and published under 
section 311(d) of the FWPCA, (33 U.S.C. 1321(d)) or revised under 
section 105 of the Comprehensive Environmental Response Compensation 
and Liability Act (42 U.S.C. 9605).
    National Contingency Plan Product Schedule means a schedule of 
dispersants and other chemical or biological products, maintained by 
the Environmental Protection Agency, that may be authorized for use on 
oil discharges in accordance with the procedures found at 40 CFR 
300.910.
    Oil means oil of any kind or in any form, including but not limited 
to petroleum, fuel oil, sludge, oil refuse, and oil mixed with wastes 
other than dredged spoil. This also includes hydrocarbons produced at 
the wellhead in liquid form (includes distillates or condensate 
associated with produced natural gas), and condensate that has been 
separated from a gas prior to injection into a pipeline. It does not 
include petroleum, including crude oil or any fraction thereof, which 
is specifically listed or designated as a hazardous substance under 
paragraphs (A) through (F) of section 101(14) of the Comprehensive 
Environmental Response, Compensation, and Liability Act (42 U.S.C. 
9601) and which is subject to the provisions of that Act. It also does 
not include animal fats and oils and greases and fish and marine mammal 
oils, within the meaning of paragraph (2) of section 61(a) of title 13, 
United States Code, and oils of vegetable origin, including oils from 
the seeds, nuts, and kernels referred to in paragraph (1)(A) of that 
section.
    Oil spill removal organization (OSRO) means an entity contracted by 
an owner or operator to provide spill-response equipment and/or 
manpower in the event of an oil or hazardous substance spill.
    Outer Continental Shelf means all submerged lands lying seaward and 
outside of the area of lands beneath navigable waters as defined in 
section 2 of the Submerged Lands Act (43 U.S.C. 1301) and of which the 
subsoil and seabed appertain to the United States and are subject to 
its jurisdiction and control.
    Owner or operator means, in the case of an offshore facility, any 
person owning or operating such offshore facility. In the case of any 
abandoned offshore facility, it means the person who owned such 
facility immediately prior to such abandonment.
    Pipeline means pipe and any associated equipment, appurtenance, or 
building used or intended for use in the transportation of oil located 
seaward of the coast line, except those used for deep-water ports. 
Pipelines do not include vessels such as barges or shuttle tankers used 
to transport oil from facilities located seaward of the coast line.
    Qualified individual means an English-speaking representative of an 
owner or operator, located in the United States, available on a 24-hour 
basis, with full authority to obligate funds, carry out removal 
actions, and communicate with the appropriate Federal officials and the 
persons providing personnel and equipment in removal operations.
    Regional Response Plan means a spill-response plan required by this 
part which covers multiple facilities or leases of an owner or 
operator, including affiliates, which are located in the same BSEE 
Region.
    Regional Supervisor means the BSEE official with responsibility and 
authority for operations or other designated program functions within a 
BSEE Region.
    Remove means containment and cleanup of oil from water and 
shorelines or the taking of other actions as may be necessary to 
minimize or mitigate damage to the public health or welfare, including, 
but not limited to, fish, shellfish, wildlife, public and private 
property, shorelines, and beaches.
    Spill is synonymous with ``discharge'' for the purposes of this 
part.
    Spill management team means the trained persons identified in a 
response plan who staff the organizational structure to manage spill 
response.
    Spill-response coordinator means a trained person charged with the 
responsibility and designated the commensurate authority for directing 
and coordinating response operations.
    Spill-response operating team means the trained persons who respond 
to spills through deployment and operation of oil-spill response 
equipment.
    State waters located seaward of the coast line means the belt of 
the seas measured from the coast line and extending seaward a distance 
of 3 miles (except the coast of Texas and the Gulf coast of Florida, 
where the State waters extend seaward a distance of 3 leagues).
    You means the owner or the operator as defined in this section.

Sec.  254.7  How do I submit my response plan to the BSEE?

    You must submit the number of copies of your response plan that the

[[Page 64607]]

appropriate BSEE regional office requires. If you prefer to use 
improved information technology such as electronic filing to submit 
your plan, ask the Regional Supervisor for further guidance.
    (a) Send plans for facilities located seaward of the coast line of 
Alaska to: Bureau of Safety and Environmental Enforcement, Regional 
Supervisor, Field Operations, Alaska OCS Region, 3801 Centerpoint 
Drive, Suite 500, Anchorage, AK 99503-5823.
    (b) Send plans for facilities in the Gulf of Mexico or Atlantic 
Ocean to: Bureau of Safety and Environmental Enforcement, Regional 
Supervisor, Field Operations, Gulf of Mexico OCS Region, 1201 Elmwood 
Park Boulevard, New Orleans, LA 70123-2394.
    (c) Send plans for facilities in the Pacific Ocean (except seaward 
of the coast line of Alaska) to: Bureau of Safety and Environmental 
Enforcement, Regional Supervisor, Office of Development Operations and 
Safety, Pacific OCS Region, 770 Paseo Camarillo, Camarillo, CA 93010-
6064.

Sec.  254.8  May I appeal decisions under this part?

    See 30 CFR part 290 for instructions on how to appeal any order or 
decision that we issue under this part.

Sec.  254.9  Authority for information collection.

    (a) The Office of Management and Budget (OMB) has approved the 
information collection requirements in this part under 44 U.S.C. 3501 
et seq. OMB assigned the control number 1010-0091. The title of this 
information collection is ``30 CFR part 254, Oil Spill Response 
Requirements for Facilities Located Seaward of the Coast line.''
    (b) BSEE collects this information to ensure that the owner or 
operator of an offshore facility is prepared to respond to an oil 
spill. BSEE uses the information to verify compliance with the mandates 
of the Oil Pollution Act of 1990 (OPA). The requirement to submit this 
information is mandatory. No confidential or proprietary information is 
collected.
    (c) An agency may not conduct or sponsor, and a person is not 
required to respond to, a collection of information unless it displays 
a currently valid OMB control number.
    (d) Send comments regarding any aspect of the collection of 
information under this part, including suggestions for reducing the 
burden, to the Information Collection Clearance Officer, Bureau of 
Safety and Environmental Enforcement, 381 Elden Street, Herndon, VA 
20170.

Subpart B--Oil-Spill Response Plans for Outer Continental Shelf 
Facilities

Sec.  254.20  Purpose.

    This subpart describes the requirements for preparing spill-
response plans for facilities located on the OCS.

Sec.  254.21  How must I format my response plan?

    (a) You must divide your response plan for OCS facilities into the 
sections specified in paragraph (b) of this section and explained in 
the other sections of this subpart. The plan must have an easily found 
marker identifying each section. You may use an alternate format if you 
include a cross-reference table to identify the location of required 
sections. You may use alternate contents if you can demonstrate to the 
Regional Supervisor that they provide for equal or greater levels of 
preparedness.
    (b) Your plan must include:
    (1) Introduction and plan contents.
    (2) Emergency response action plan.
    (3) Appendices:
    (i) Equipment inventory.
    (ii) Contractual agreements.
    (iii) Worst case discharge scenario.
    (iv) Dispersant use plan.
    (v) In situ burning plan.
    (vi) Training and drills.

Sec.  254.22  What information must I include in the ``Introduction and 
plan contents'' section?

    The ``Introduction and plan contents'' section must provide:
    (a) Identification of the facility the plan covers, including its 
location and type;
    (b) A table of contents;
    (c) A record of changes made to the plan; and
    (d) A cross-reference table, if needed, because you are using an 
alternate format for your plan.

Sec.  254.23  What information must I include in the ``Emergency 
response action plan'' section?

    The ``Emergency response action plan'' section is the core of the 
response plan. Put information in easy-to-use formats such as flow 
charts or tables where appropriate. This section must include:
    (a) Designation, by name or position, of a trained qualified 
individual (QI) who has full authority to implement removal actions and 
ensure immediate notification of appropriate Federal officials and 
response personnel.
    (b) Designation, by name or position, of a trained spill management 
team available on a 24-hour basis. The team must include a trained 
spill-response coordinator and alternate(s) who have the responsibility 
and authority to direct and coordinate response operations on your 
behalf. You must describe the team's organizational structure as well 
as the responsibilities and authorities of each position on the spill 
management team.
    (c) Description of a spill-response operating team. Team members 
must be trained and available on a 24-hour basis to deploy and operate 
spill-response equipment. They must be able to respond within a 
reasonable minimum specified time. You must include the number and 
types of personnel available from each identified labor source.
    (d) A planned location for a spill-response operations center and 
provisions for primary and alternate communications systems available 
for use in coordinating and directing spill-response operations. You 
must provide telephone numbers for the response operations center. You 
also must provide any facsimile numbers and primary and secondary radio 
frequencies that will be used.
    (e) A listing of the types and characteristics of the oil handled, 
stored, or transported at the facility.
    (f) Procedures for the early detection of a spill.
    (g) Identification of procedures you will follow in the event of a 
spill or a substantial threat of a spill. The procedures should show 
appropriate response levels for differing spill sizes including those 
resulting from a fire or explosion. These will include, as appropriate:
    (1) Your procedures for spill notification. The plan must provide 
for the use of the oil spill reporting forms included in the Area 
Contingency Plan or an equivalent reporting form.
    (i) Your procedures must include a current list which identifies 
the following by name or position, corporate address, and telephone 
number (including facsimile number if applicable):
    (A) The qualified individual;
    (B) The spill-response coordinator and alternate(s); and
    (C) Other spill-response management team members.
    (ii) You must also provide names, telephone numbers, and addresses 
for the following:
    (A) OSRO's that the plan cites;
    (B) Federal, State, and local regulatory agencies that you must 
consult to obtain site specific environmental information; and
    (C) Federal, State, and local regulatory agencies that you must 
notify when an oil spill occurs.
    (2) Your methods to monitor and predict spill movement;

[[Page 64608]]

    (3) Your methods to identify and prioritize the beaches, waterfowl, 
other marine and shoreline resources, and areas of special economic and 
environmental importance;
    (4) Your methods to protect beaches, waterfowl, other marine and 
shoreline resources, and areas of special economic or environmental 
importance;
    (5) Your methods to ensure that containment and recovery equipment 
as well as the response personnel are mobilized and deployed at the 
spill site;
    (6) Your methods to ensure that devices for the storage of 
recovered oil are sufficient to allow containment and recovery 
operations to continue without interruption;
    (7) Your procedures to remove oil and oiled debris from shallow 
waters and along shorelines and rehabilitating waterfowl which become 
oiled;
    (8) Your procedures to store, transfer, and dispose of recovered 
oil and oil-contaminated materials and to ensure that all disposal is 
in accordance with Federal, State, and local requirements; and
    (9) Your methods to implement your dispersant use plan and your in 
situ burning plan.

Sec.  254.24  What information must I include in the ``Equipment 
inventory'' appendix?

    Your ``Equipment inventory appendix'' must include:
    (a) An inventory of spill-response materials and supplies, 
services, equipment, and response vessels available locally and 
regionally. You must identify each supplier and provide their locations 
and telephone numbers.
    (b) A description of the procedures for inspecting and maintaining 
spill-response equipment in accordance with Sec.  254.43.

Sec.  254.25  What information must I include in the ``Contractual 
agreements'' appendix?

    Your ``Contractual agreements'' appendix must furnish proof of any 
contracts or membership agreements with OSRO's, cooperatives, spill-
response service providers, or spill management team members who are 
not your employees that you cite in the plan. To provide this proof, 
submit copies of the contracts or membership agreements or certify that 
contracts or membership agreements are in effect. The contract or 
membership agreement must include provisions for ensuring the 
availability of the personnel and/or equipment on a 24-hour-per-day 
basis.

Sec.  254.26  What information must I include in the ``Worst case 
discharge scenario'' appendix?

    The discussion of your worst case discharge scenario must include 
all of the following elements:
    (a) The volume of your worst case discharge scenario determined 
using the criteria in Sec.  254.47. Provide any assumptions made and 
the supporting calculations used to determine this volume.
    (b) An appropriate trajectory analysis specific to the area in 
which the facility is located. The analysis must identify onshore and 
offshore areas that a discharge potentially could affect. The 
trajectory analysis chosen must reflect the maximum distance from the 
facility that oil could move in a time period that it reasonably could 
be expected to persist in the environment.
    (c) A list of the resources of special economic or environmental 
importance that potentially could be impacted in the areas identified 
by your trajectory analysis. You also must state the strategies that 
you will use for their protection. At a minimum, this list must include 
those resources of special economic and environmental importance, if 
any, specified in the appropriate Area Contingency Plan(s).
    (d) A discussion of your response to your worst case discharge 
scenario in adverse weather conditions. This discussion must include:
    (1) A description of the response equipment that you will use to 
contain and recover the discharge to the maximum extent practicable. 
This description must include the types, location(s) and owner, 
quantity, and capabilities of the equipment. You also must include the 
effective daily recovery capacities, where applicable. You must 
calculate the effective daily recovery capacities using the methods 
described in Sec.  254.44. For operations at a drilling or production 
facility, your scenario must show how you will cope with the initial 
spill volume upon arrival at the scene and then support operations for 
a blowout lasting 30 days.
    (2) A description of the personnel, materials, and support vessels 
that would be necessary to ensure that the identified response 
equipment is deployed and operated promptly and effectively. Your 
description must include the location and owner of these resources as 
well as the quantities and types (if applicable);
    (3) A description of your oil storage, transfer, and disposal 
equipment. Your description must include the types, location and owner, 
quantity, and capacities of the equipment; and
    (4) An estimation of the individual times needed for:
    (i) Procurement of the identified containment, recovery, and 
storage equipment;
    (ii) Procurement of equipment transportation vessel(s);
    (iii) Procurement of personnel to load and operate the equipment;
    (iv) Equipment loadout (transfer of equipment to transportation 
vessel(s));
    (v) Travel to the deployment site (including any time required for 
travel from an equipment storage area); and
    (vi) Equipment deployment.
    (e) In preparing the discussion required by paragraph (d) of this 
section, you must:
    (1) Ensure that the response equipment, materials, support vessels, 
and strategies listed are suitable, within the limits of current 
technology, for the range of environmental conditions anticipated at 
your facility; and
    (2) Use standardized, defined terms to describe the range of 
environmental conditions anticipated and the capabilities of response 
equipment. Examples of acceptable terms include those defined in 
American Society for Testing of Materials (ASTM) publication F625-94, 
Standard Practice for Describing Environmental Conditions Relevant to 
Spill Control Systems for Use on Water, and ASTM F818-93, Standard 
Definitions Relating to Spill Response Barriers.

Sec.  254.27  What information must I include in the ``Dispersant use 
plan'' appendix?

    Your dispersant use plan must be consistent with the National 
Contingency Plan Product Schedule and other provisions of the National 
Contingency Plan and the appropriate Area Contingency Plan(s). The plan 
must include:
    (a) An inventory and a location of the dispersants and other 
chemical or biological products which you might use on the oils 
handled, stored, or transported at the facility;
    (b) A summary of toxicity data for these products;
    (c) A description and a location of any application equipment 
required as well as an estimate of the time to commence application 
after approval is obtained;
    (d) A discussion of the application procedures;
    (e) A discussion of the conditions under which product use may be 
requested; and
    (f) An outline of the procedures you must follow in obtaining 
approval for product use.

[[Page 64609]]

Sec.  254.28  What information must I include in the ``In situ burning 
plan'' appendix?

    Your in situ burning plan must be consistent with any guidelines 
authorized by the National Contingency Plan and the appropriate Area 
Contingency Plan(s). Your in situ burning plan must include:
    (a) A description of the in situ burn equipment including its 
availability, location, and owner;
    (b) A discussion of your in situ burning procedures, including 
provisions for ignition of an oil spill;
    (c) A discussion of environmental effects of an in situ burn;
    (d) Your guidelines for well control and safety of personnel and 
property;
    (e) A discussion of the circumstances in which in situ burning may 
be appropriate;
    (f) Your guidelines for making the decision to ignite; and
    (g) An outline of the procedures you must follow to obtain approval 
for an in situ burn.

Sec.  254.29  What information must I include in the ``Training and 
drills'' appendix?

    Your ``Training and drills'' appendix must:
    (a) Identify and include the dates of the training provided to 
members of the spill-response management team and the qualified 
individual. The types of training given to the members of the spill-
response operating team also must be described. The training 
requirements for your spill management team and your spill-response 
operating team are specified in Sec.  254.41. You must designate a 
location where you keep course completion certificates or attendance 
records for this training.
    (b) Describe in detail your plans for satisfying the exercise 
requirements of Sec.  254.42. You must designate a location where you 
keep the records of these exercises.

Sec.  254.30  When must I revise my response plan?

    (a) You must review your response plan at least every 2 years and 
submit all resulting modifications to the Regional Supervisor. If this 
review does not result in modifications, you must inform the Regional 
Supervisor in writing that there are no changes.
    (b) You must submit revisions to your plan for approval within 15 
days whenever:
    (1) A change occurs which significantly reduces your response 
capabilities;
    (2) A significant change occurs in the worst case discharge 
scenario or in the type of oil being handled, stored, or transported at 
the facility;
    (3) There is a change in the name(s) or capabilities of the oil 
spill removal organizations cited in the plan; or
    (4) There is a significant change to the Area Contingency Plan(s).
    (c) The Regional Supervisor may require that you resubmit your plan 
if the plan has become outdated or if numerous revisions have made its 
use difficult.
    (d) The Regional Supervisor will periodically review the equipment 
inventories of OSRO's to ensure that sufficient spill removal equipment 
is available to meet the cumulative needs of the owners and operators 
who cite these organizations in their plans.
    (e) The Regional Supervisor may require you to revise your plan if 
significant inadequacies are indicated by:
    (1) Periodic reviews (described in paragraph (d) of this section);
    (2) Information obtained during drills or actual spill responses; 
or
    (3) Other relevant information the Regional Supervisor obtained.

Subpart C--Related Requirements for Outer Continental Shelf 
Facilities

Sec.  254.40  Records.

    You must make all records of services, personnel, and equipment 
provided by OSRO's or cooperatives available to any authorized BSEE 
representative upon request.

Sec.  254.41  Training your response personnel.

    (a) You must ensure that the members of your spill-response 
operating team who are responsible for operating response equipment 
attend hands-on training classes at least annually. This training must 
include the deployment and operation of the response equipment they 
will use. Those responsible for supervising the team must be trained 
annually in directing the deployment and use of the response equipment.
    (b) You must ensure that the spill-response management team, 
including the spill-response coordinator and alternates, receives 
annual training. This training must include instruction on:
    (1) Locations, intended use, deployment strategies, and the 
operational and logistical requirements of response equipment;
    (2) Spill reporting procedures;
    (3) Oil-spill trajectory analysis and predicting spill movement; 
and
    (4) Any other responsibilities the spill management team may have.
    (c) You must ensure that the qualified individual is sufficiently 
trained to perform his or her duties.
    (d) You must keep all training certificates and training attendance 
records at the location designated in your response plan for at least 2 
years. They must be made available to any authorized BSEE 
representative upon request.

Sec.  254.42  Exercises for your response personnel and equipment.

    (a) You must exercise your entire response plan at least once every 
3 years (triennial exercise). You may satisfy this requirement by 
conducting separate exercises for individual parts of the plan over the 
3-year period; you do not have to exercise your entire response plan at 
one time.
    (b) In satisfying the triennial exercise requirement, you must, at 
a minimum, conduct:
    (1) An annual spill management team tabletop exercise. The exercise 
must test the spill management team's organization, communication, and 
decision making in managing a response. You must not reveal the spill 
scenario to team members before the exercise starts.
    (2) An annual deployment exercise of response equipment identified 
in your plan that is staged at onshore locations. You must deploy and 
operate each type of equipment in each triennial period. However, it is 
not necessary to deploy and operate each individual piece of equipment.
    (3) An annual notification exercise for each facility that is 
manned on a 24- hour basis. The exercise must test the ability of 
facility personnel to communicate pertinent information in a timely 
manner to the qualified individual.
    (4) A semiannual deployment exercise of any response equipment 
which the BSEE Regional Supervisor requires an owner or operator to 
maintain at the facility or on dedicated vessels. You must deploy and 
operate each type of this equipment at least once each year. Each type 
need not be deployed and operated at each exercise.
    (c) During your exercises, you must simulate conditions in the area 
of operations, including seasonal weather variations, to the extent 
practicable. The exercises must cover a range of scenarios over the 3-
year exercise period, simulating responses to large continuous spills, 
spills of short duration and limited volume, and your worst case 
discharge scenario.
    (d) BSEE will recognize and give credit for any documented exercise 
conducted that satisfies some part of the required triennial exercise. 
You will receive this credit whether the owner or operator, an OSRO, or 
a Government

[[Page 64610]]

regulatory agency initiates the exercise. BSEE will give you credit for 
an actual spill response if you evaluate the response and generate a 
proper record. Exercise documentation should include the following 
information:
    (1) Type of exercise;
    (2) Date and time of the exercise;
    (3) Description of the exercise;
    (4) Objectives met; and
    (5) Lessons learned.
    (e) All records of spill-response exercises must be maintained for 
the complete 3-year exercise cycle. Records should be maintained at the 
facility or at a corporate location designated in the plan. Records 
showing that OSRO's and oil spill removal cooperatives have deployed 
each type of equipment also must be maintained for the 3-year cycle.
    (f) You must inform the Regional Supervisor of the date of any 
exercise required by paragraph (b)(1), (2), or (4) of this section at 
least 30 days before the exercise. This will allow BSEE personnel the 
opportunity to witness any exercises.
    (g) The Regional Supervisor periodically will initiate unannounced 
drills to test the spill response preparedness of owners and operators.
    (h) The Regional Supervisor may require changes in the frequency or 
location of the required exercises, equipment to be deployed and 
operated, or deployment procedures or strategies. The Regional 
Supervisor may evaluate the results of the exercises and advise the 
owner or operator of any needed changes in response equipment, 
procedures, or strategies.
    (i) Compliance with the National Preparedness for Response Exercise 
Program (PREP) Guidelines will satisfy the exercise requirements of 
this section. Copies of the PREP document may be obtained from the 
Regional Supervisor.

Sec.  254.43  Maintenance and periodic inspection of response 
equipment.

    (a) You must ensure that the response equipment listed in your 
response plan is inspected at least monthly and is maintained, as 
necessary, to ensure optimal performance.
    (b) You must ensure that records of the inspections and the 
maintenance activities are kept for at least 2 years and are made 
available to any authorized BSEE representative upon request.

Sec.  254.44  Calculating response equipment effective daily recovery 
capacities.

    (a) You are required by Sec.  254.26(d)(1) to calculate the 
effective daily recovery capacity of the response equipment identified 
in your response plan that you would use to contain and recover your 
worst case discharge. You must calculate the effective daily recovery 
capacity of the equipment by multiplying the manufacturer's rated 
throughput capacity over a 24-hour period by 20 percent. This 20 
percent efficiency factor takes into account the limitations of the 
recovery operations due to available daylight, sea state, temperature, 
viscosity, and emulsification of the oil being recovered. You must use 
this calculated rate to determine if you have sufficient recovery 
capacity to respond to your worst case discharge scenario.
    (b) If you want to use a different efficiency factor for specific 
oil recovery devices, you must submit evidence to substantiate that 
efficiency factor. Adequate evidence includes verified performance data 
measured during actual spills or test data gathered according to the 
provisions of Sec.  254.45(b) and (c).

Sec.  254.45  Verifying the capabilities of your response equipment.

    (a) The Regional Supervisor may require performance testing of any 
spill-response equipment listed in your response plan to verify its 
capabilities if the equipment:
    (1) Has been modified;
    (2) Has been damaged and repaired; or
    (3) Has a claimed effective daily recovery capacity that is 
inconsistent with data otherwise available to BSEE.
    (b) You must conduct any required performance testing of booms in 
accordance with BSEE-approved test criteria. You may use the document 
``Test Protocol for the Evaluation of Oil-Spill Containment Booms,'' 
available from BSEE, for guidance. Performance testing of skimmers also 
must be conducted in accordance with BSEE approved test criteria. You 
may use the document ``Suggested Test Protocol for the Evaluation of 
Oil Spill Skimmers for the OCS,'' available from BSEE, for guidance.
    (c) You are responsible for any required testing of equipment 
performance and for the accuracy of the information submitted.

Sec.  254.46  Whom do I notify if an oil spill occurs?

    (a) You must immediately notify the National Response Center (1-
800-424-8802) if you observe:
    (1) An oil spill from your facility;
    (2) An oil spill from another offshore facility; or
    (3) An offshore spill of unknown origin.
    (b) In the event of a spill of 1 barrel or more from your facility, 
you must orally notify the Regional Supervisor without delay. You also 
must report spills from your facility of unknown size but thought to be 
1 barrel or more.
    (1) If a spill from your facility not originally reported to the 
Regional Supervisor is subsequently found to be 1 barrel or more, you 
must then report it without delay.
    (2) You must file a written follow up report for any spill from 
your facility of 1 barrel or more. The Regional Supervisor must receive 
this confirmation within 15 days after the spillage has been stopped. 
All reports must include the cause, location, volume, and remedial 
action taken. Reports of spills of more than 50 barrels must include 
information on the sea state, meteorological conditions, and the size 
and appearance of the slick. The Regional Supervisor may require 
additional information if it is determined that an analysis of the 
response is necessary.
    (c) If you observe a spill resulting from operations at another 
offshore facility, you must immediately notify the responsible party 
and the Regional Supervisor.

Sec.  254.47  Determining the volume of oil of your worst case 
discharge scenario.

    You must calculate the volume of oil of your worst case discharge 
scenario as follows:
    (a) For an oil production platform facility, the size of your worst 
case discharge scenario is the sum of the following:
    (1) The maximum capacity of all oil storage tanks and flow lines on 
the facility. Flow line volume may be estimated; and
    (2) The volume of oil calculated to leak from a break in any 
pipelines connected to the facility considering shutdown time, the 
effect of hydrostatic pressure, gravity, frictional wall forces and 
other factors; and
    (3) The daily production volume from an uncontrolled blowout of the 
highest capacity well associated with the facility. In determining the 
daily discharge rate, you must consider reservoir characteristics, 
casing/production tubing sizes, and historical production and reservoir 
pressure data. Your scenario must discuss how to respond to this well 
flowing for 30 days as required by Sec.  254.26(d)(1).
    (b) For exploratory or development drilling operations, the size of 
your worst case discharge scenario is the daily volume possible from an 
uncontrolled blowout. In determining the daily discharge rate, you must 
consider any known reservoir characteristics. If reservoir 
characteristics are unknown, you must

[[Page 64611]]

consider the characteristics of any analog reservoirs from the area and 
give an explanation for the selection of the reservoir(s) used. Your 
scenario must discuss how to respond to this well flowing for 30 days 
as required by Sec.  254.26(d)(1).
    (c) For a pipeline facility, the size of your worst case discharge 
scenario is the volume possible from a pipeline break. You must 
calculate this volume as follows:
    (1) Add the pipeline system leak detection time to the shutdown 
response time.
    (2) Multiply the time calculated in paragraph (c)(1) of this 
section by the highest measured oil flow rate over the preceding 12-
month period. For new pipelines, you should use the predicted oil flow 
rate in the calculation.
    (3) Add to the volume calculated in paragraph (c)(2) of this 
section the total volume of oil that would leak from the pipeline after 
it is shut in. Calculate this volume by taking into account the effects 
of hydrostatic pressure, gravity, frictional wall forces, length of 
pipeline segment, tie-ins with other pipelines, and other factors.
    (d) If your facility which stores, handles, transfers, processes, 
or transports oil does not fall into the categories listed in paragraph 
(a), (b), or (c) of this section, contact the Regional Supervisor for 
instructions on the calculation of the volume of your worst case 
discharge scenario.

Subpart D--Oil-Spill Response Requirements for Facilities Located 
in State Waters Seaward of the Coast Line

Sec.  254.50  Spill response plans for facilities located in State 
waters seaward of the coast line.

    Owners or operators of facilities located in State waters seaward 
of the coast line must submit a spill-response plan to BSEE for 
approval. You may choose one of three methods to comply with this 
requirement. The three methods are described in Sec. Sec.  254.51, 
254.52, and 254.53.

Sec.  254.51  Modifying an existing OCS response plan.

    You may modify an existing response plan covering a lease or 
facility on the OCS to include a lease or facility in State waters 
located seaward of the coast line. Since this plan would cover more 
than one lease or facility, it would be considered a Regional Response 
Plan. You should refer to Sec.  254.3 and contact the appropriate 
regional BSEE office if you have any questions on how to prepare this 
Regional Response Plan.

Sec.  254.52  Following the format for an OCS response plan.

    You may develop a response plan following the requirements for 
plans for OCS facilities found in subpart B of this part.

Sec.  254.53  Submitting a response plan developed under State 
requirements.

    (a) You may submit a response plan to BSEE for approval that you 
developed in accordance with the laws or regulations of the appropriate 
State. The plan must contain all the elements the State and OPA require 
and must:
    (1) Be consistent with the requirements of the National Contingency 
Plan and appropriate Area Contingency Plan(s).
    (2) Identify a qualified individual and require immediate 
communication between that person and appropriate Federal officials and 
response personnel if there is a spill.
    (3) Identify any private personnel and equipment necessary to 
remove, to the maximum extent practicable, a worst case discharge as 
defined in Sec.  254.47. The plan must provide proof of contractual 
services or other evidence of a contractual agreement with any OSRO's 
or spill management team members who are not employees of the owner or 
operator.
    (4) Describe the training, equipment testing, periodic unannounced 
drills, and response actions of personnel at the facility. These must 
ensure both the safety of the facility and the mitigation or prevention 
of a discharge or the substantial threat of a discharge.
    (5) Describe the procedures you will use to periodically update and 
resubmit the plan for approval of each significant change.
    (b) Your plan developed under State requirements also must include 
the following information:
    (1) A list of the facilities and leases the plan covers and a map 
showing their location;
    (2) A list of the types of oil handled, stored, or transported at 
the facility;
    (3) Name and address of the State agency to whom the plan was 
submitted;
    (4) Date you submitted the plan to the State;
    (5) If the plan received formal approval, the name of the approving 
organization, the date of approval, and a copy of the State agency's 
approval letter if one was issued; and
    (6) Identification of any regulations or standards used in 
preparing the plan.

Sec.  254.54  Spill prevention for facilities located in State waters 
seaward of the coast line.

    In addition to your response plan, you must submit to the Regional 
Supervisor a description of the steps you are taking to prevent spills 
of oil or mitigate a substantial threat of such a discharge. You must 
identify all State or Federal safety or pollution prevention 
requirements that apply to the prevention of oil spills from your 
facility, and demonstrate your compliance with these requirements. You 
also should include a description of industry safety and pollution 
prevention standards your facility meets. The Regional Supervisor may 
prescribe additional equipment or procedures for spill prevention if it 
is determined that your efforts to prevent spills do not reflect good 
industry practices.

PART 256--LEASING OF SULPHUR OR OIL AND GAS IN THE OUTER 
CONTINENTAL SHELF

Subpart A--Outer Continental Shelf Oil, Gas, and Sulphur Management, 
General
Sec.
256.0 [Reserved]
256.1 Purpose.
256.2-256.5 [Reserved]
256.7 Cross references.
256.8-256.12 [Reserved]
Subpart B--Oil and Gas Leasing Program [Reserved]
Subpart C--Reports From Federal Agencies [Reserved]
Subpart D--Call for Information and Nominations [Reserved]
Subpart E--Area and Identification and Tract Size [Reserved]
Subpart F--Lease Sales [Reserved]
Subpart G--Issuance of Leases [Reserved]
Subpart H--Rentals and Royalties [Reserved]
Subpart I--Bonding [Reserved]
Subpart J--Assignments, Transfers, and Extensions
256.62-256.68 [Reserved]
256.70 Extension of lease by drilling or well reworking operations.
256.71 Directional drilling.
256.72 Compensatory payments as production.
256.73 Effect of suspensions on lease term.
Subpart K--Termination of Leases
256.76 [Reserved]
256.77 Cancellation of leases.
Subpart L--Section 6 Leases
256.79 Effect of regulations on lease.
256.80 [Reserved]

[[Page 64612]]

Subpart M--Studies [Reserved]
Subpart N--Bonus or Royalty Credits for Exchange of Certain Leases 
Offshore Florida [Reserved]

    Authority: 31 U.S.C. 9701, 42 U.S.C. 6213, 43 U.S.C. 1334, Pub. 
L. 109-432.

Subpart A--Outer Continental Shelf Oil, Gas, and Sulphur 
Management, General

Sec.  256.0  [Reserved]

Sec.  256.1  Purpose.

    The purpose of the regulations in 30 CFR part 256 is to establish 
the procedures under which the Secretary of the Interior (Secretary) 
will exercise the authority to administer a leasing program for oil, 
gas and sulphur. The procedures under which the Secretary will exercise 
the authority to administer a program to grant rights-of-way, are 
addressed in part 250, Subpart J.

Sec. Sec.  256.2-256.5  [Reserved]

Sec.  256.7  Cross references.

    (a) For Bureau of Safety and Environmental Enforcement (BSEE) 
regulations governing exploration, development and production on 
leases, see 30 CFR parts 250 and 270.
    (b) For BSEE regulations governing the appeal of an order or 
decision issued under the regulations in this part, see 30 CFR part 
290.
    (c) For multiple use conflicts, see the Environmental Protection 
Agency listing of ocean dumping sites--40 CFR part 228.
    (d) For related National Oceanic and Atmospheric Administration 
programs see:
    (1) Marine sanctuary regulations, 15 CFR part 922;
    (2) Fishermen's Contingency Fund, 50 CFR part 296;
    (3) Coastal Energy Impact Program, 15 CFR part 931;
    (e) For Coast Guard regulations on the oil spill liability of 
vessels and operators, see 33 CFR parts 132, 135, and 136.
    (f) For Coast Guard regulations on port access routes, see 33 CFR 
part 164.
    (g) For compliance with the National Environmental Policy Act, see 
40 CFR parts 1500 through 1508.
    (h) For Department of Transportation regulations on offshore 
pipeline facilities, see 49 CFR part 195.
    (i) For Department of Defense regulations on military activities on 
offshore areas, see 32 CFR part 252.

Sec. Sec.  256.8-256.12  [Reserved]

Subpart B--Oil and Gas Leasing Program [Reserved]

Subpart C--Reports From Federal Agencies [Reserved]

Subpart D--Call for Information and Nominations [Reserved]

Subpart E--Area and Identification and Tract Size [Reserved]

Subpart F--Lease Sales [Reserved]

Subpart H--Rentals and Royalties [Reserved]

Subpart I--Bonding [Reserved]

Subpart J--Assignments, Transfers, and Extensions

    Sec. Sec.  256.62-256.68 [Reserved]

Sec.  256.70  Extension of lease by drilling or well reworking 
operations.

    The term of a lease shall be extended beyond the primary term so 
long as drilling or well reworking operations are approved by the 
Secretary according to the conditions set forth in 30 CFR 250.180.

Sec.  256.71  Directional drilling.

    In accordance with a BOEM-approved exploration plan or development 
and production plan, a lease may be maintained in force by directional 
wells drilled under the leased area from surface locations on adjacent 
or adjoining land not covered by the lease. In such circumstances, 
drilling shall be considered to have commenced on the leased area when 
drilling is commenced on the adjacent or adjoining land for the purpose 
of directional drilling under the leased area through any directional 
well surfaced on adjacent or adjoining land. Production, drilling or 
reworking of any such directional well shall be considered production 
or drilling or reworking operations on the leased area for all purposes 
of the lease.

Sec.  256.72  Compensatory payments as production.

    If an oil and gas lessee makes compensatory payments and if the 
lease is not being maintained in force by other production of oil or 
gas in paying quantities or by other approved drilling or reworking 
operations, such payments shall be considered as the equivalent of 
production in paying quantities for all purposes of the lease.

Sec.  256.73  Effect of suspensions on lease term.

    (a) A suspension may extend the term of a lease (see 30 CFR 
250.171) with the extension being the length of time the suspension is 
in effect except as provided in paragraph (b) of this section.
    (b) A Directed Suspension does not extend the lease term when the 
Regional Supervisor directs a suspension because of:
    (1) Gross negligence; or
    (2) A willful violation of a provision of the lease or governing 
regulations.
    (c) BSEE may issue suspensions for a period of up to 5 years per 
suspension. The Regional Supervisor will set the length of the 
suspension based on the conditions of the individual case involved. 
BSEE may grant consecutive suspensions. For more information on 
suspension of operations or production refer to the section under the 
heading ``Suspensions'' in 30 CFR part 250, subpart A.

Subpart K--Termination of Leases

Sec.  256.76  [Reserved]

Sec.  256.77  Cancellation of leases.

    (a) Any nonproducing lease issued under the act may be cancelled by 
the authorized officer whenever the lessee fails to comply with any 
provision of the act or lease or applicable regulations, if such 
failure to comply continues for 30 days after mailing of notice by 
registered or certified letter to the lease owner at the owner's record 
post office address. Any such cancellation is subject to judicial 
review as provided in section 23(b) of the Act.
    (b) Producing leases issued under the Act may be cancelled by the 
Secretary whenever the lessee fails to comply with any provision of the 
Act, applicable regulations or the lease only after judicial 
proceedings as prescribed by section 5(d) of the Act.
    (c) Any lease issued under the Act, whether producing or not, shall 
be canceled by the authorized officer upon proof that it was obtained 
by fraud or misrepresentation, and after notice and opportunity to be 
heard has been afforded to the lessee.
    (d) Pursuant to section 5(a) of the Act, the Secretary may cancel a 
lease when:
    (1) Continued activity pursuant to such lease would probably cause 
serious harm or damage to life, property, any mineral, National 
security or defense, or to the marine, coastal or human environment;
    (2) The threat of harm or damage will not disappear or decrease to 
an acceptable extent within a reasonable period of time; and

[[Page 64613]]

    (3) The advantages of cancellation outweigh the advantages of 
continuing such lease or permit in force. Procedures and conditions 
contained in Sec.  550.182 shall apply as appropriate.

Subpart L--Section 6 Leases

Sec.  256.79  Effect of regulations on lease.

    (a) All regulations in this part, insofar as they are applicable, 
shall supersede the provisions of any lease which is maintained under 
section 6(a) of the Act. However, the provisions of a lease relating to 
area, minerals, rentals, royalties (subject to sections 6(a) (8) and 
(9) of the Act), and term (subject to section 6(a)(10) of the Act and, 
as to sulfur, subject to section 6(b)(2) of the Act) shall continue in 
effect, and, in the event of any conflict or inconsistency, shall take 
precedence over these regulations.
    (b) A lease maintained under section 6(a) of the Act shall also be 
subject to all operating and conservation regulations applicable to the 
OCS. In addition, the regulations relating to geophysical and 
geological exploratory operations and to pipeline rights-of-way are 
applicable, to the extent that those regulations are not contrary to or 
inconsistent with the lease provisions relating to area, the minerals, 
rentals, royalties and term. The lessee shall comply with any provision 
of the lease as validated, the subject matter of which is not covered 
in the regulations in this part.

Sec.  256.80  [Reserved]

Subpart M--Studies [Reserved]

Subpart N--Bonus or Royalty Credits for Exchange of Certain Leases 
Offshore Florida [Reserved]

PART 259--[RESERVED]

PART 260--[RESERVED]

PART 270--NONDISCRIMINATION IN THE OUTER CONTINENTAL SHELF

Sec.
270.1 Purpose.
270.2 Application of this part.
270.3 Definitions.
270.4 Discrimination prohibited.
270.5 Complaint.
270.6 Process.
270.7 Remedies.

    Authority: 43 U.S.C. 1863.

Sec.  270.1  Purpose.

    The purpose of this part is to implement the provisions of section 
604 of the OCSLA of 1978 which provides that ``no person shall, on the 
grounds of race, creed, color, national origin, or sex, be excluded 
from receiving or participating in any activity, sale, or employment, 
conducted pursuant to the provisions of * * * the Outer Continental 
Shelf Lands Act.''

Sec.  270.2  Application of this part.

    This part applies to any contract or subcontract entered into by a 
lessee or by a contractor or subcontractor of a lessee after the 
effective date of these regulations to provide goods, services, 
facilities, or property in an amount of $10,000 or more in connection 
with any activity related to the exploration for or development and 
production of oil, gas, or other minerals or materials in the OCS under 
the Act.

Sec.  270.3  Definitions.

    As used in this part, the following terms shall have the following 
meanings:
    Contract means any business agreement or arrangement (in which the 
parties do not stand in the relationship of employer and employee) 
between a lessee and any person which creates an obligation to provide 
goods, services, facilities, or property.
    Lessee means the party authorized by a lease, grant of right-of-
way, or an approved assignment thereof to explore, develop, produce, or 
transport oil, gas, or other minerals or materials in the OCS pursuant 
to the Act and this part.
    Person means a person or company, including but not limited to, a 
corporation, partnership, association, joint stock venture, trust, 
mutual fund, or any receiver, trustee in bankruptcy, or other official 
acting in a similar capacity for such company.
    Subcontract means any business agreement or arrangement (in which 
the parties do not stand in the relationship of employer and employee) 
between a lessee's contractor and any person other than a lessee that 
is in any way related to the performance of any one or more contracts.

Sec.  270.4  Discrimination prohibited.

    No contract or subcontract to which this part applies shall be 
denied to or withheld from any person on the grounds of race, creed, 
color, national origin, or sex.

Sec.  270.5  Complaint.

    (a) Whenever any person believes that he or she has been denied a 
contract or subcontract to which this part applies on the grounds of 
race, creed, color, national origin, or sex, such person may complain 
of such denial or withholding to the Regional Director of the OCS 
Region in which such action is alleged to have occurred. Any complaint 
filed under this part must be submitted in writing to the appropriate 
Regional Director not later than 180 days after the date of the alleged 
unlawful denial of a contract or subcontract which is the basis of the 
complaint.
    (b) The complaint referred to in paragraph (a) of this section 
shall be accompanied by such evidence as may be available to a person 
and which is relevant to the complaint including affidavits and other 
documents.
    (c) Whenever any person files a complaint under this part, the 
Regional Director with whom such complaint is filed shall give written 
notice of such filing to all persons cited in the complaint no later 
than 10 days after receipt of such complaint. Such notice shall include 
a statement describing the alleged incident of discrimination, 
including the date and the names of persons involved in it.

Sec.  270.6  Process.

    Whenever a Regional Director determines on the basis of any 
information, including that which may be obtained under Sec.  270.5 of 
this part, that a violation of or failure to comply with any provision 
of this subpart probably occurred, the Regional director shall 
undertake to afford the complainant and the person(s) alleged to have 
violated the provisions of this part an opportunity to engage in 
informal consultations, meetings, or any other form of communications 
for the purpose of resolving the complaint. In the event such 
communications or consultations result in a mutually satisfactory 
resolution of the complaint, the complainant and all persons cited in 
the complaint shall notify the Regional Director in writing of their 
agreement to such resolution. If either the complainant or the 
person(s) alleged to have wrongfully discriminated fail to provide such 
written notice within a reasonable period of time, the Regional 
Director must proceed in accordance with the provisions of 30 CFR 250, 
subpart N.

Sec.  270.7  Remedies.

    In addition to the penalties available under 30 CFR part 250, 
subpart N, the Director may invoke any other remedies available to him 
or her under the Act or regulations for the lessee's failure to comply 
with provisions of the Act, regulations, or lease.

[[Page 64614]]

PART 280--PROSPECTING FOR MINERALS OTHER THAN OIL, GAS, AND SULPHUR 
ON THE OUTER CONTINENTAL SHELF

Subpart A--[Reserved]
Subpart B--[Reserved]
Subpart C--Obligations Under This Part

Interrupted Activities

Sec.
280.20-280.24 [Reserved]
280.25 When may BSEE require me to stop activities under this part?
280.26 When may I resume activities?
280.27 When may BSEE cancel my permit?
280.28 May I relinquish my permit?
Subpart D--[Reserved]
Subpart E--[Reserved]

    Authority: 43 U.S.C. 1334.

Subpart C--Obligations Under This Part

Interrupted Activities

Sec. Sec.  280.20-280.24  [Reserved]

Sec.  280.25  When may BSEE require me to stop activities under this 
part?

    (a) We may temporarily stop prospecting or scientific research 
activities under a permit when the Regional Director determines that:
    (1) Activities pose a threat of serious, irreparable, or immediate 
harm. This includes damage to life (including fish and other aquatic 
life), property, and any minerals (in areas leased or not leased), to 
the marine, coastal, or human environment, or to an archaeological 
resource;
    (2) You failed to comply with any applicable law, regulation, order 
or provision of the permit. This would include our required submission 
of reports, well records or logs, and G&G data and information within 
the time specified; or
    (3) Stopping the activities is in the interest of National security 
or defense.
    (b) The Regional Director will advise you either orally or in 
writing of the procedures to temporarily stop activities. We will 
confirm an oral notification in writing and deliver all written 
notifications by courier or certified/registered mail. You must stop 
all activities under a permit as soon as you receive an oral or written 
notification.

Sec.  280.26  When may I resume activities?

    The Regional Director will advise you when you may start your 
permit activities again.

Sec.  280.27  When may BSEE cancel my permit?

    The Regional Director may cancel a permit at any time.
    (a) If we cancel your permit, the Regional Director will advise you 
by certified or registered mail 30 days before the cancellation date 
and will state the reason.
    (b) After we cancel your permit, you are still responsible for 
proper abandonment of any drill site according to the requirements of 
30 CFR 251.7(b)(8). You must comply with all other obligations 
specified in this part or in the permit.

Sec.  280.28  May I relinquish my permit?

    (a) You may relinquish your permit at any time by advising the 
Regional Director by certified or registered mail 30 days in advance.
    (b) After you relinquish your permit, you are still responsible for 
proper abandonment of any drill sites according to the requirements of 
30 CFR 251.7(b)(8). You must also comply with all other obligations 
specified in this part or in the permit.

Subpart D--[Reserved]

Subpart E--[Reserved]

PART 281--[RESERVED]

PART 282--OPERATIONS IN THE OUTER CONTINENTAL SHELF FOR MINERALS 
OTHER THAN OIL, GAS, AND SULPHUR

Subpart A--General
Sec.
282.0 Authority for information collection.
282.1 Purpose and authority.
282.2 Scope.
282.3 Definitions.
282.4 [Reserved]
282.5 Disclosure of data and information to the public.
282.6 Disclosure of data and information to an adjacent State.
282.7 Jurisdictional controversies.
Subpart B--Jurisdiction and Responsibilities of Director
282.10 Jurisdiction and responsibilities of Director.
282.11 Director's authority.
282.12 Director's responsibilities.
282.13 Suspension of production or other operations.
282.14 Noncompliance, remedies, and penalties.
282.15 [Reserved]
Subpart C--Obligations and Responsibilities of Lessees
282.20 [Reserved]
282.21 Plans, general.
282.22--282.26 [Reserved]
282.27 Conduct of operations.
282.28 Environmental protection measures.
282.29 [Reserved]
282.30 [Reserved]
282.31 Suspension of production or other operations.
Subpart D--Payments
282.40 [Reserved]
282.41 Method of royalty calculation
282.42 [Reserved]
Subpart E--Appeals
282.50 Appeals.

    Authority: 43 U.S.C. 1334.

Subpart A--General

Sec.  282.0  Authority for information collection.

    The information collection requirements in this part have been 
approved by the Office of Management and Budget under 44 U.S.C. 3507 
and assigned clearance number 1010-0081. The information is being 
collected to inform the Bureau of Safety and Environmental Enforcement 
(BSEE) of general mining operations in the Outer Continental Shelf 
(OCS). The information will be used to ensure that operations are 
conducted in a safe and environmentally responsible manner in 
compliance with governing laws and regulations. The requirement to 
respond is mandatory.

Sec.  282.1  Purpose and authority.

    (a) The Act authorizes the Secretary to prescribe such rules and 
regulations as may be necessary to carry out the provisions of the Act 
(43 U.S.C. 1334). The Secretary is authorized to prescribe and amend 
regulations that the Secretary determines to be necessary and proper in 
order to provide for the prevention of waste, conservation of the 
natural resources of the OCS, and the protection of correlative rights 
therein. In the enforcement of safety, environmental, and conservation 
laws and regulations, the Secretary is authorized to cooperate with 
adjacent States and other Departments and Agencies of the Federal 
Government.
    (b) Subject to the supervisory authority of the Secretary, and 
unless otherwise specified, the regulations in this part shall be 
administered by the Director of BSEE.

Sec.  282.2  Scope.

    The rules and regulations in this part apply as of their effective 
date to all operations conducted under a mineral lease for OCS minerals 
other than oil, gas, or sulphur issued under the provisions of section 
8(k) of the Act.

Sec.  282.3  Definitions.

    When used in this part, the following terms shall have the 
following meaning:

[[Page 64615]]

    Act means the OCS Lands Act, as amended (43 U.S.C. 1331 et seq.).
    Adjacent State means with respect to any activity proposed, 
conducted, or approved under this part, any coastal State:
    (1) That is, or is proposed to be, receiving for processing, 
refining, or transshipment OCS mineral resources commercially recovered 
from the seabed;
    (2) That is used, or is scheduled to be used, as a support base for 
prospecting, exploration, testing, or mining activities; or
    (3) In which there is a reasonable probability of significant 
effect on land or water uses from such activity.
    Contingency Plan means a plan for action to be taken in emergency 
situations.
    Data means geological and geophysical (G&G) facts and statistics or 
samples which have not been analyzed, processed, or interpreted.
    Development means those activities which take place following the 
discovery of minerals in paying quantities including geophysical 
activities, drilling, construction of offshore facilities, and 
operation of all onshore support facilities, which are for the purpose 
of ultimately producing the minerals discovered.
    Director means the Director of BSEE of the U.S. Department of the 
Interior or an official authorized to act on the Director's behalf.
    Exploration means the process of searching for minerals on a lease 
including:
    (1) Geophysical surveys where magnetic, gravity, seismic, or other 
systems are used to detect or imply the presence of minerals;
    (2) Any drilling including the drilling of a borehole in which the 
discovery of a mineral other than oil, gas, or sulphur is made and the 
drilling of any additional boreholes needed to delineate any mineral 
deposits; and
    (3) The taking of sample portions of a mineral deposit to enable 
the lessee to determine whether to proceed with development and 
production.
    Geological sample means a collected portion of the seabed, the 
subseabed, or the overylying waters (when obtained for geochemical 
analysis) acquired while conducting postlease mining activities.
    Governor means the Governor of a State or the person or entity 
designated by, or pursuant to, State law to exercise the power granted 
to a Governor.
    Information means G&G data that have been analyzed, processed, or 
interpreted.
    Lease means one of the following, whichever is required by the 
context: Any form of authorization which is issued under section 8 or 
maintained under section 6 of the Acts and which authorizes exploration 
for, and development and production of, specific minerals; or the area 
covered by that authorization.
    Lessee means the person authorized by a lease, or an approved 
assignment thereof, to explore for and develop and produce the leased 
deposits in accordance with the regulations in this chapter. The term 
includes all parties holding that authority by or through the lessee.
    Major Federal action means any action or proposal by the Secretary 
which is subject to the provisions of section 102(2)(C) of the National 
Environmental Policy Act (NEPA) (i.e., an action which will have a 
significant impact on the quality of the human environment requiring 
preparation of an Environmental Impact Statement (EIS) pursuant to 
section 102(2)(C) of NEPA).
    Marine environment means the physical, atmospheric, and biological 
components, conditions, and factors which interactively determine the 
productivity, state, condition, and quality of the marine ecosystem, 
including the waters of the high seas, the contiguous zone, 
transitional and intertidal areas, salt marshes, and wetlands within 
the coastal zone and on the OCS.
    Minerals include oil, gas, sulphur, geopressured-geothermal and 
associated resources, and all other minerals which are authorized by an 
Act of Congress to be produced from ``public lands'' as defined in 
section 103 of the Federal Land Policy and Management Act of 1976.
    OCS mineral means any mineral deposit or accretion found on or 
below the surface of the seabed but does not include oil, gas, or 
sulphur; salt or sand and gravel intended for use in association with 
the development of oil, gas, or sulphur; or source materials essential 
to production of fissionable materials which are reserved to the United 
States pursuant to section 12(e) of the Act.
    Operator means the individual, partnership, firm, or corporation 
having control or management of operations on the lease or a portion 
thereof. The operator may be a lessee, designated agent of the lessee, 
or holder of rights under an approved operating agreement.
    Outer Continental Shelf means all submerged lands lying seaward and 
outside of the area of lands beneath navigable waters as defined in 
section 2 of Submerged Lands Act (43 U.S.C. 1301) and of which the 
subsoil and seabed appertain to the United States and are subject to 
its jurisdiction and control.
    Person means a citizen or national of the United States; an alien 
lawfully admitted for permanent residency in the United States as 
defined in 8 U.S.C. 1101(a)(20); a private, public, or municipal 
corporation organized under the laws of the United States or of any 
State or territory thereof; an association of such citizens, nationals, 
resident aliens or private, public, or municipal corporations, States, 
or political subdivisions of States; or anyone operating in a manner 
provided for by treaty or other applicable international agreements. 
The term does not include Federal Agencies.
    Secretary means the Secretary of the Interior or an official 
authorized to act on the Secretary's behalf.
    Testing means removing bulk samples for processing tests and 
feasibility studies and/or the testing of mining equipment to obtain 
information needed to develop a detailed Mining Plan.

Sec.  282.4  [Reserved]

Sec.  282.5  Disclosure of data and information to the public.

    (a) The Director shall make data, information, and samples 
available in accordance with the requirements and subject to the 
limitations of the Act, the Freedom of Information Act (5 U.S.C. 552), 
and the implementing regulations (43 CFR part 2).
    (b) Geophysical data, processed G&G information, interpreted G&G 
information, and other data and information submitted pursuant to the 
requirements of this part shall not be available for public inspection 
without the consent of the lessee so long as the lease remains in 
effect, unless the Director determines that earlier limited release of 
such information is necessary for the unitization of operations on two 
or more leases, to ensure proper Mining Plans for a common ore body, or 
to promote operational safety. When the Director determines that early 
limited release of data and information is necessary, the data and 
information shall be shown only to persons with a direct interest in 
the affected lease(s), unitization agreement, or joint Mining Plan.
    (c) Geophysical data, processed geophysical information and 
interpreted geophysical information collected on a lease with high 
resolution systems (including, but not limited to, bathymetry, side-
scan sonar, subbottom profiler, and magnetometer) in compliance with 
stipulations or orders concerning protection of environmental aspects 
of the lease may be made

[[Page 64616]]

available to the public 60 days after submittal to the Director, unless 
the lessee can demonstrate to the satisfaction of the Director that 
release of the information or data would unduly damage the lessee's 
competitive position.

Sec.  282.6  Disclosure of data and information to an adjacent State.

    (a) Proprietary data, information, and samples submitted to BSEE 
pursuant to the requirements of this part shall be made available for 
inspection by representatives of adjacent State(s) upon request by the 
Governor(s) in accordance with paragraphs (b) and (c) of this section.
    (b) Disclosure shall occur only after the Governor has entered into 
an agreement with the Secretary providing that:
    (1) The confidentiality of the information shall be maintained;
    (2) In any action commenced against the Federal Government or the 
State for failure to protect the confidentiality of proprietary 
information, the Federal Government or the State, as the case may be, 
may not raise as a defense any claim of sovereign immunity or any claim 
that the employee who revealed the proprietary information, which is 
the basis of the suit, was acting outside the scope of the person's 
employment in revealing the information;
    (3) The State agrees to hold the United States harmless for any 
violation by the State or its employees or contractors of the agreement 
to protect the confidentiality of proprietary data, information, and 
samples; and
    (c) The data, information, and samples available for inspection by 
representatives of adjacent State(s) pursuant to an agreement shall be 
related to leased lands.

Sec.  282.7  Jurisdictional controversies.

    In the event of a controversy between the United States and a State 
as to whether certain lands are subject to Federal or State 
jurisdiction, either the Governor of the State or the Secretary may 
initiate negotiations in an attempt to settle the jurisdictional 
controversy. With the concurrence of the Attorney General, the 
Secretary may enter into an agreement with a State with respect to OCS 
mineral activities and to payment and impounding of rents, royalties, 
and other sums and with respect to the issuance or nonissuance of new 
leases pending settlement of the controversy.

Subpart B--Jurisdiction and Responsibilities of Director

Sec.  282.10  Jurisdiction and responsibilities of Director.

    Subject to the authority of the Secretary, the following activities 
are subject to the regulations in this part and are under the 
jurisdiction of the Director: Exploration, testing, and mining 
operations together with the associated environmental protection 
measures needed to permit those activities to be conducted in an 
environmentally responsible manner; handling, measurement, and 
transportation of OCS minerals; and other operations and activities 
conducted pursuant to a lease issued under 30 CFR part 581, or pursuant 
to a right of use and easement granted under 30 CFR 582.30, by or on 
behalf of a lessee or the holder of a right of use and easement.

Sec.  282.11  Director's authority.

    (a)-(c) [Reserved]
    (d)(1) The Director may approve the consolidation of two or more 
OCS mineral leases or portions of two or more OCS mineral leases into a 
single mining unit requested by lessees, or the Director may require 
such consolidation when the operation of those leases or portions of 
leases as a single mining unit is in the interest of conservation of 
the natural resources of the OCS or the prevention of waste. A mining 
unit may also include all or portions of one or more OCS mineral leases 
with all or portions of one or more adjacent State leases for minerals 
in a common orebody. A single unit operator shall be responsible for 
submission of required Delineation, Testing, and Mining Plans covering 
OCS mineral operations for an approved mining unit.
    (2) Operations such as exploration, testing, and mining activities 
conducted in accordance with an approved plan on any lease or portion 
of a lease which is subject to an approved mining unit shall be 
considered operations on each of the leases that is made subject to the 
approved mining unit.
    (3) Minimum royalty paid pursuant to a Federal lease, which is 
subject to an approved mining unit, is creditable against the 
production royalties allocated to that Federal lease during the lease 
year for which the minimum royalty is paid.
    (4) Any OCS minerals produced from State and Federal leases which 
are subject to an approved mining unit shall be accounted for 
separately unless a method of allocating production between State and 
Federal leases has been approved by the Director and the appropriate 
State official.

Sec.  282.12  Director's responsibilities.

    (a) The Director is responsible for the regulation of activities to 
assure that all operations conducted under a lease or right of use and 
easement are conducted in a manner that protects the environment and 
promotes orderly development of OCS mineral resources. Those activities 
are to be designed to prevent serious harm or damage to, or waste of, 
any natural resource (including OCS mineral deposits and oil, gas, and 
sulphur resources in areas leased or not leased), any life (including 
fish and other aquatic life), property, or the marine, coastal, or 
human environment.
    (b)-(d) [Reserved]
    (e) The Director shall assure that a scheduled onsite compliance 
inspection of each facility which is subject to regulations in this 
part is conducted at least once a year. The inspection shall be to 
determine that the lessee is in compliance with the requirements of the 
law; provisions of the lease; the approved Delineation, Testing, or 
Mining Plan; and the regulations in this part. Additional unscheduled 
onsite inspections shall be conducted without advance notice to the 
lessee to assure compliance with the provisions of applicable law; the 
lease; the approved Delineation, Testing, or Mining Plan; and the 
regulations in this part.
    (f)(1) The Director shall, after completion of the technical and 
environmental evaluations, approve, disapprove, or require modification 
of the lessee's requests, applications, plans, and notices submitted 
pursuant to the provisions of this part; issue orders to govern lease 
operations; and require compliance with applicable provisions of the 
law, the regulations, the lease, and the approved Delineation, Testing, 
or Mining Plans. The Director may give oral orders or approvals 
whenever prior approval is required before the commencement of an 
operation or activity. Oral orders or approvals given in response to a 
written request shall be confirmed in writing within 3 working days 
after issuance of the order or granting of the oral approval.
    (2) The Director shall, after completion of the technical and 
environmental evaluations, approve, disapprove, or require 
modification, as appropriate, of the design plan, fabrication plan, and 
installation plan for platforms, artificial islands, and other 
installations and devices permanently or temporarily attached to the 
seabed. The approval, disapproval,

[[Page 64617]]

or requirement to modify such plans may take the form of a condition of 
granting a right of use and easement under paragraph (a) of this 
section or as authorized under any lease issued or maintained under the 
Act.
    (g) [Reserved]
    (h) The Director may prescribe or approve, in writing or orally, 
departures from the operating requirements of the regulations of this 
part when such departures are necessary to facilitate the proper 
development of a lease; to conserve natural resources; or to protect 
life (including fish and other aquatic life), property, or the marine, 
coastal, or human environment.

Sec.  282.13  Suspension of production or other operations.

    (a) The Director may direct the suspension or temporary prohibition 
of production or any other operation or activity on all or any part of 
a lease when it has been determined that such suspension or temporary 
prohibition is in the National interest to:
    (1) Facilitate proper development of a lease including a reasonable 
time to develop a mine and construct necessary support facilities, or
    (2) Allow for the construction or negotiation for use of 
transportation facilities.
    (b) The Director may also direct or, at the request of the lessee, 
approve a suspension or temporary prohibition of production or any 
other operation or activity, if:
    (1) The lessee failed to comply with a provision of applicable law, 
regulation, order, or the lease;
    (2) There is a threat of serious, irreparable, or immediate harm or 
damage to life (including fish and other aquatic life), property, any 
mineral deposit, or the marine, coastal, or human environment;
    (3) The suspension or temporary prohibition is in the interest of 
National security or defense;
    (4) The suspension or temporary prohibition is necessary for the 
initiation and conduct of an environmental evaluation to define 
mitigation measures to avoid or minimize adverse environmental impacts.
    (5) The suspension or temporary prohibition is necessary to 
facilitate the installation of equipment necessary for safety of 
operations and protection of the environment;
    (6) The suspension or temporary prohibition is necessary to allow 
for undue delays encountered by the lessee in obtaining required 
permits or consents, including administrative or judicial challenges or 
appeals;
    (7) The Director determines that continued operations would result 
in premature abandonment of a producing mine, resulting in the loss of 
otherwise recoverable OCS minerals;
    (8) The Director determines that the lessee cannot successfully 
operate a producing mine due to market conditions that are either 
temporary in nature or require temporary shutdown and reinvestment in 
order for the lessee to adapt to the conditions; or
    (9) The suspension or temporary prohibition is necessary to comply 
with judicial decrees prohibiting production or any other operation or 
activity, or the permitting of those activities, effective the date set 
by the court for that prohibition.
    (c) When the Director orders or approves a suspension or a 
temporary prohibition of operation or activity including production on 
all of a lease pursuant to paragraph (a) or (b) of this section, the 
term of the lease shall be extended for a period of time equal to the 
period of time that the suspension or temporary prohibition is in 
effect, except that no lease shall be so extended when the suspension 
or temporary prohibition is the result of the lessee's gross negligence 
or willful violation of a provision of the lease or governing 
regulations.
    (d) The Director may, at any time within the period prescribed for 
a suspension or temporary prohibition issued pursuant to paragraph 
(b)(2) of this section, require the lessee to submit a Delineation, 
Testing, or Mining Plan for approval in accordance with the 
requirements for the approval of such plans in this part.
    (e)(1) When the Director orders or issues a suspension or a 
temporary prohibition pursuant to paragraph (b)(2) of this section, the 
Director may require the lessee to conduct site-specific studies to 
identify and evaluate the cause(s) of the hazard(s) generating the 
suspension or temporary prohibition, the potential for damage from the 
hazard(s), and the measures available for mitigating the hazard(s). The 
nature, scope, and content of any study shall be subject to approval by 
the Director. The lessee shall furnish copies and all results of any 
such study to the Director. The cost of the study shall be borne by the 
lessee unless the Director arranges for the cost of the study to be 
borne by a party other than the lessee. The Director shall make results 
of any such study available to interested parties and to the public as 
soon as practicable after the completion of the study and submission of 
the results thereof.
    (2) When the Director determines that measures are necessary, on 
the basis of the results of the studies conducted in accordance with 
paragraph (e)(1) of this section and other information available to and 
identified by the Director, the lessee shall be required to take 
appropriate measures to mitigate, avoid, or minimize the damage or 
potential damage on which the suspension or temporary prohibition is 
based. When deemed appropriate by the Director, the lessee shall submit 
a revised Delineation, Testing, or Mining Plan to incorporate the 
mitigation measures required by the Director. In choosing between 
alternative mitigation measures, the Director shall balance the cost of 
the required measures against the reduction or potential reduction in 
damage or threat of damage or harm to life (including fish and other 
aquatic life), to property, to any mineral deposits (in areas leased or 
not leased), to the National security or defense, or to the marine, 
coastal, or human environment.
    (f)(1) If under the provisions of paragraphs (b)(2), (3), and (4) 
of this section, the Director, with respect to any lease, directs the 
suspension of production or other operations on the entire leasehold, 
no payment of rental or minimum royalty shall be due for or during the 
period of the directed suspension and the time for the lessee specify 
royalty free period of a period of reduced royalty pursuant to 30 CFR 
581.28(b) will be extended for the period of directed suspension. If 
under the provisions of paragraphs (b)(2), (3), and (4) of this section 
the Director, with respect to a lease on which there has been no 
production, directs the suspension of operations on the entire 
leasehold, no payment of rental shall be due during the period of the 
directed suspension.
    (2) If under the provisions of this section, the Director grants 
the request of a lessee for a suspension of production or other 
operations, the lessee's obligations to pay rental, minimum royalty, or 
royalty shall continue to apply during the period of the approved 
suspension, unless the Director's approval of the lessee's request for 
suspension authorizes the payment of a lesser amount during the period 
of approved suspension. If under the provision of this section, the 
Director grants a lessee's request for a suspension of production or 
other operations for a lease which includes provisions for a time 
period which the lessee may specify during which production from the 
leasehold would be royalty free or subject to a reduced royalty 
obligation pursuant to 30 CFR 581.28(b), the time during which 
production from a leasehold may be

[[Page 64618]]

royalty free or subject to a reduced royalty obligation shall not be 
extended unless the Director's approval of the suspension specifies 
otherwise.
    (3) If the lease anniversary date falls within a period of 
suspension for which no rental or minimum royalty payments are required 
under paragraph (a) of this section, the prorated rentals or minimum 
royalties are due and payable as of the date the suspension period 
terminates. These amounts shall be computed and notice thereof given 
the lessee. The lessee shall pay the amount due within 30 days after 
receipt of such notice. The anniversary date of a lease shall not 
change by reason of any period of lease suspension or rental or royalty 
relief resulting therefrom.

Sec.  282.14  Noncompliance, remedies, and penalties.

    (a)(1) If the Director determines that a lessee has failed to 
comply with applicable provisions of law; the regulations in this part; 
other applicable regulations; the lease; the approved Delineation, 
Testing, or Mining Plan; or the Director's orders or instructions, and 
the Director determines that such noncompliance poses a threat of 
immediate, serious, or irreparable damage to the environment, the mine 
or the deposit being mined, or other valuable mineral deposits or other 
resources, the Director shall order the lessee to take immediate and 
appropriate remedial action to alleviate the threat. Any oral orders 
shall be followed up by service of a notice of noncompliance upon the 
lessee by delivery in person to the lessee or agent, or by certified or 
registered mail addressed to the lessee at the last known address.
    (2) If the Director determines that the lessee has failed to comply 
with applicable provisions of law; the regulations in this part; other 
applicable regulations; the lease; the requirements of an approved 
Delineation, Testing, or Mining Plan; or the Director's orders or 
instructions, and such noncompliance does not pose a threat of 
immediate, serious, or irreparable damage to the environment, the mine 
or the deposit being mined, or other valuable mineral deposits or other 
resources, the Director shall serve a notice of noncompliance upon the 
lessee by delivery in person to the lessee or agent or by certified or 
registered mail addressed to the lessee at the last known address.
    (b) A notice of noncompliance shall specify in what respect(s) the 
lessee has failed to comply with the provisions of applicable law; 
regulations; the lease; the requirements of an approved Delineation, 
Testing, or Mining Plan; or the Director's orders or instructions, and 
shall specify the action(s) which must be taken to correct the 
noncompliance and the time limits within which such action must be 
taken.
    (c) Failure of a lessee to take the actions specified in the notice 
of noncompliance within the time limit specified shall be grounds for a 
suspension of operations and other appropriate actions, including but 
not limited to the assessment of a civil penalty of up to $10,000 per 
day for each violation that is not corrected within the time period 
specified (43 U.S.C. 1350(b)).
    (d) Whenever the Director determines that a violation of or failure 
to comply with any provision of the Act; or any provision of a lease, 
license, or permit issued pursuant to the Act; or any provision of any 
regulation promulgated under the Act probably occurred and that such 
apparent violation continued beyond notice of the violation and the 
expiration of the reasonable time period allowed for corrective action, 
the Director shall follow the procedures concerning remedies and 
penalties in subpart N, Remedies and Penalties, of 30 CFR part 250 to 
determine and assess an appropriate penalty.
    (e) The remedies and penalties prescribed in this section shall be 
concurrent and cumulative, and the exercise of one shall not preclude 
the exercise of the other. Further, the remedies and penalties 
prescribed in this section shall be in addition to any other remedies 
and penalties afforded by any other law or regulation (43 U.S.C. 
1350(e)).

Sec.  282.15  [Reserved]

Subpart C--Obligations and Responsibilities of Lessees

Sec.  282.20  [Reserved]

Sec.  282.21  Plans, general.

    (a)-(d) [Reserved]
    (e) Leasehold activities shall be carried out with due regard to 
conservation of resources, paying particular attention to the wise 
management of OCS mineral resources, minimizing waste of the leased 
resource(s) in mining and processing, and preventing damage to unmined 
parts of the mineral deposit and other resources of the OCS.

Sec. Sec.  282.22-282.26  [Reserved]

Sec.  282.27  Conduct of operations.

    (a) The lessee shall conduct all exploration, testing, development, 
and production activities and other operations in a safe and 
workmanlike manner and shall maintain equipment in a manner which 
assures the protection of the lease and its improvements, the health 
and safety of all persons, and the conservation of property, and the 
environment.
    (b) Nothing in this part shall preclude the use of new or 
alternative technologies, techniques, procedures, equipment, or 
activities, other than those prescribed in the regulations of this 
part, if such other technologies, techniques, procedures, equipment, or 
activities afford a degree of protection, safety, and performance equal 
to or better than that intended to be achieved by the regulations of 
this part, provided the lessee obtains the written approval of the 
Director prior to the use of such new or alternative technologies, 
techniques, procedures, equipment, or activities.
    (c) The lessee shall immediately notify the Director when there is 
a death or serious injury; fire, explosion, or other hazardous event 
which threatens damage to life, a mineral deposit, or equipment; spills 
of oil, chemical reagents, or other liquid pollutants which could cause 
pollution; or damage to aquatic life or the environment associated with 
operations on the lease. As soon as practical, the lessee shall file a 
detailed report on the event and action(s) taken to control the 
situation and to mitigate any further damage.
    (d)(1) Lessees shall provide means, at all reasonable hours either 
day or night, for the Director to inspect or investigate the conditions 
of the operation and to determine whether applicable regulations; terms 
and conditions of the lease; and the requirements of the approved 
Delineation, Testing, or Mining Plan are being met.
    (2) A lessee shall, on request by the Director, furnish food, 
quarters, and transportation for BSEE representatives to inspect its 
facilities. Upon request, the lessee will be reimbursed by the United 
States for the actual costs which it incurs as a result of its 
providing food, quarters, and transportation for a BSEE 
representative's stay of more than 10 hours. Request for reimbursement 
must be submitted within 60 days following the cost being incurred.
    (e) Mining and processing vessels, platforms, structures, 
artificial islands, and mobile drilling units which have helicopter 
landing facilities shall be identified with at least one sign using 
letters and figures not less than 12 inches in height. Signs for 
structures without helicopter landing facilities shall be identified 
with at least one sign using letters and figures not less than 3 inches 
in height. Signs shall be affixed at a location that is visible to

[[Page 64619]]

approaching traffic and shall contain the following information which 
may be abbreviated:
    (1) Name of the lease operator;
    (2) The area designation based on Official OCS Protraction 
Diagrams;
    (3) The block number in which the facility is located; and
    (4) Vessel, platform, structure, or rig name.
    (f)(1) Drilling. (i) When drilling on lands valuable or potentially 
valuable for oil and gas or geopressured or geothermal resources, 
drilling equipment shall be equipped with blowout prevention and 
control devices acceptable to the Director before penetrating more than 
500 feet unless a different depth is specified in advance by the 
Director.
    (ii) In cases where the Director determines that there is 
sufficient likelihood of encountering pressurized hydrocarbons, the 
Director may require that the lessee comply with all or portions of the 
requirements in part 250, subpart D, of this title.
    (iii) Before drilling any hole which may penetrate an aquifer, the 
lessee shall follow the procedures included in the approved plan for 
the penetration and isolation of the aquifer during the drilling 
operation, during use of the hole, and for subsequent abandonment of 
the hole.
    (iv) Cuttings from holes drilled on the lease shall be disposed of 
and monitored in accordance with the approved plan.
    (v) The use of muds in drilling holes on the lease and their 
subsequent disposition shall be according to the approved plan.
    (2) All drill holes which are susceptible to logging shall be 
logged, and the lessee shall prepare a detailed lithologic log of each 
drill hole. Drill holes which are drilled deeper than 500 feet shall be 
drilled in a manner which permits logging. Copies of logs of cores and 
cuttings and all in-hole surveys such as electronic logs, gamma ray 
logs, neutron density logs, and sonic logs shall be provided to the 
Director.
    (3) Drill holes for exploration, testing, development, or 
production shall be properly plugged and abandoned to the satisfaction 
of the Director in accordance with the approved plan and in such a 
manner as to protect the surface and not endanger any operation; any 
freshwater aquifer; or deposit of oil, gas, or other mineral substance.
    (g) The use of explosives on the lease shall be in accordance with 
the approved plan.
    (h)(1) Any equipment placed on the seabed shall be designed to 
allow its recovery and removal upon abandonment of leasehold 
activities.
    (2) Disposal of equipment, cables, chains, containers, or other 
materials into the ocean is prohibited.
    (3) Materials, equipment, tools, containers, and other items used 
on the OCS which are of such shape or configuration that they are 
likely to snag or damage fishing devices shall be handled and marked as 
follows:
    (i) All loose materials, small tools, and other small objects shall 
be kept in a suitable storage area or a marked container when not in 
use or in a marked container before transport over OCS waters;
    (ii) All cable, chain, or wire segments shall be recovered after 
use and securely stored;
    (iii) Skid-mounted equipment, portable containers, spools or reels, 
and drums shall be marked with the owner's name prior to use or 
transport over OCS waters; and
    (iv) All markings must clearly identify the owner and must be 
durable enough to resist the effects of the environmental conditions to 
which they are exposed.
    (4) Any equipment or material described in paragraphs (h)(2), 
(h)(3)(ii), and (iii) of this section that is lost overboard shall be 
recorded on the daily operations report of the facility and reported to 
the Director and to the U.S. Coast Guard.
    (i) Any bulk sampling or testing that is necessary to be conducted 
prior to submission of a Mining Plan shall be in accordance with an 
approved Testing Plan. The sale of any OCS minerals acquired under an 
approved Testing Plan shall be subject to the payment of the royalty 
specified in the lease to the United States.
    (j) Installations and structures: (1) The lessee shall design, 
fabricate, install, use, inspect, and maintain all installations and 
structures, including platforms on the OCS, to assure the structural 
integrity of all installations and structures for the safe conduct of 
exploration, testing, mining, and processing activities considering the 
specific environmental conditions at the location of the installation 
or structure.
    (2) All fixed or bottom-founded platforms or other structures, 
e.g., artificial islands shall be designed, fabricated, installed, 
inspected, and maintained in accordance with the provisions of 30 CFR 
part 250, subpart I.
    (k) The lessee shall not produce any OCS mineral until the method 
of measurement and the procedures for product valuation have been 
instituted in accordance with the approved Testing or Mining Plan. The 
lessee shall enter the weight or quantity and quality of each mineral 
produced in accordance with 30 CFR 582.29.
    (l) The lessee shall conduct OCS mineral processing operations in 
accordance with the approved Testing or Mining Plan and use due 
diligence in the reduction, concentration, or separation of mineral 
substances by mechanical or chemical processes, by evaporation, or 
other means, so that the percentage of concentrates or other mineral 
substances are recovered in accordance with the practices approved in 
the Testing or Mining Plan.
    (m) No material shall be discharged or disposed of except in 
accordance with the approved disposal practice and procedures contained 
in the approved Delineation, Testing, or Mining Plan.

Sec.  282.28  Environmental protection measures.

    (a)-(b) [Reserved]
    (c)(1) The lessee shall monitor activities in a manner that 
develops the data and information necessary to enable the Director to 
assess the impacts of exploration, testing, mining, and processing 
activities on the environment on and off the lease; develop and 
evaluate methods for mitigating adverse environmental effects; validate 
assessments made in previous environmental evaluations; and ensure 
compliance with lease and other requirements for the protection of the 
environment.
    (2) Monitoring of environmental effects shall include determination 
of the spatial and temporal environmental changes induced by the 
exploration, testing, development, production, and processing 
activities on the flora and fauna of the sea surface, the water column, 
and/or the seafloor.
    (3) The Director may place observers onboard exploration, testing, 
mining, and processing vessels; installations; or structures to ensure 
that the provisions of the lease, the approved plan, and these 
regulations are followed and to evaluate the effectiveness of the 
approved monitoring and mitigation practices and procedures in 
protecting the environment.
    (4) The Director may order or the lessee may request a modification 
of the approved monitoring program prior to the startup of testing 
activities or commercial-scale recovery, and at other appropriate times 
as necessary, to reflect accurately the proposed operations or to 
incorporate the results of recent research or improved monitoring 
techniques.
    (5) [Reserved]
    (6) When required, the monitoring plan will specify:

[[Page 64620]]

    (i) The sampling techniques and procedures to be used to acquire 
the needed data and information;
    (ii) The format to be used in analysis and presentation of the data 
and information;
    (iii) The equipment, techniques, and procedures to be used in 
carrying out the monitoring program; and
    (iv) The name and qualifications of person(s) designated to be 
responsible for carrying out the environmental monitoring.
    (d) Lessees shall develop and conduct their operations in a manner 
designed to avoid, minimize, or otherwise mitigate environmental 
impacts and to demonstrate the effectiveness of efforts to that end. 
Based upon results of the monitoring program, the Director may specify 
particular procedures for mitigating environmental impacts.
    (e) [Reserved]

Sec.  282.29  [Reserved]

Sec.  282.30  [Reserved]

Sec.  282.31  Suspension of production or other operations.

    A lessee may submit a request for a suspension of production or 
other operations. The request shall include justification for granting 
the requested suspension, a schedule of work leading to the initiation 
or restoration of production or other operations, and any other 
information the Director may require.

Subpart D--Payments

Sec.  282.40  [Reserved]

Sec.  282.41  Method of royalty calculation.

    In the event that the provisions of royalty management regulations 
in part 1206 of chapter XII do not apply to the specific commodities 
produced under regulations in this part, the lessee shall comply with 
procedures specified in the leasing notice.

Sec.  282.42  [Reserved]

Subpart E--Appeals

Sec.  282.50  Appeals.

    See 30 CFR part 290 for instructions on how to appeal any order or 
decision that we issue under this part.

PART 285--[RESERVED]

SUBCHAPTER C--APPEALS

PART 290--APPEAL PROCEDURES

Subpart A--Bureau of Safety and Environmental Enforcement Appeal 
Procedures
Sec.
290.1 What is the purpose of this subpart?
290.2 Who may appeal?
290.3 What is the time limit for filing an appeal?
290.4 How do I file an appeal?
290.5 Can I obtain an extension for filing my Notice of Appeal?
290.6 Are informal resolutions permitted?
290.7 Do I have to comply with the decision or order while my appeal 
is pending?
290.8 How do I exhaust my administrative remedies?
Subpart B [Reserved]

    Authority: 5 U.S.C. 301 et seq.; 43 U.S.C. 1331.

Subpart A--Bureau of Safety and Environmental Enforcement Appeal 
Procedures

Sec.  290.1  What is the purpose of this subpart?

    The purpose of this subpart is to explain the procedures for 
appeals of Bureau of Safety and Environmental Enforcement (BSEE) 
decisions and orders issued under 30 CFR chapter II.

Sec.  290.2  Who may appeal?

    If you are adversely affected by a BSEE official's final decision 
or order issued under 30 CFR chapter II, you may appeal that decision 
or order to the Interior Board of Land Appeals (IBLA). Your appeal must 
conform with the procedures found in this subpart and 43 CFR part 4, 
subpart E.

Sec.  290.3  What is the time limit for filing an appeal?

    You must file your appeal within 60 days after you receive BSEE's 
final decision or order. The 60-day time period applies rather than the 
time period provided in 43 CFR 4.411(a). A decision or order is 
received on the date you sign a receipt confirming delivery or, if 
there is no receipt, the date otherwise documented.

Sec.  290.4  How do I file an appeal?

    For your appeal to be filed, BSEE must receive all of the following 
within 60 days after you receive the decision or order:
    (a) A written Notice of Appeal together with a copy of the decision 
or order you are appealing in the office of the BSEE officer that 
issued the decision or order. You cannot extend the 60-day period for 
that office to receive your Notice of Appeal; and
    (b) A nonrefundable processing fee of $150 paid with the Notice of 
Appeal.
    (1) You must pay electronically through Pay.gov at: https://www.pay.gov/paygov/, and you must include a copy of the Pay.gov 
confirmation receipt page with your Notice of Appeal.
    (2) You cannot extend the 60-day period for payment of the 
processing fee.

Sec.  290.5  Can I obtain an extension for filing my Notice of Appeal?

    You cannot obtain an extension of time to file the Notice of 
Appeal. See 43 CFR 4.411(c).

Sec.  290.6  Are informal resolutions permitted?

    (a) You may seek informal resolution with the issuing officer's 
next level supervisor during the 60-day period established in Sec.  
290.3.
    (b) Nothing in this subpart precludes resolution by settlement of 
any appeal or matter pending in the administrative process after the 
60-day period established in Sec.  290.3.

Sec.  290.7  Do I have to comply with the decision or order while my 
appeal is pending?

    (a) The decision or order is effective during the 60-day period for 
filing an appeal under Sec.  290.3 unless:
    (1) BSEE notifies you that the decision or order, or some portion 
of it, is suspended during this period because there is no likelihood 
of immediate and irreparable harm to human life, the environment, any 
mineral deposit, or property; or
    (2) You post a surety bond under 30 CFR 250.1409 pending the appeal 
challenging an order to pay a civil penalty.
    (b) This section applies rather than 43 CFR 4.21(a) for appeals of 
BSEE orders.
    (c) After you file your appeal, IBLA may grant a stay of a decision 
or order under 43 CFR 4.21(b); however, a decision or order remains in 
effect until IBLA grants your request for a stay of the decision or 
order under appeal.

Sec.  290.8  How do I exhaust my administrative remedies?

    (a) If you receive a decision or order issued under chapter II, 
subchapter B, you must appeal that decision or order to IBLA under 43 
CFR part 4, subpart E to exhaust administrative remedies.
    (b) This section does not apply if the Assistant Secretary for Land 
and Minerals Management or the IBLA makes a decision or order 
immediately effective notwithstanding an appeal.

Subpart B--[Reserved]

PART 291--OPEN AND NONDISCRIMINATORY ACCESS TO OIL AND GAS 
PIPELINES UNDER THE OUTER CONTINENTAL SHELF LANDS ACT

Sec.

[[Page 64621]]

291.1 What is BSEE's authority to collect information?
291.100 What is the purpose of this part?
291.101 What definitions apply to this part?
291.102 May I call the BSEE Hotline to informally resolve an 
allegation that open and nondiscriminatory access was denied?
291.103 May I use alternative dispute resolution (ADR) to informally 
resolve an allegation that and nondiscriminatory access was denied?
291.104 Who may file a complaint or a third-party brief?
291.105 What must a complaint contain?
291.106 How do I file a complaint?
291.107 How do I answer a complaint?
291.108 How do I pay the processing fee?
291.109 Can I ask for a fee waiver or a reduced processing fee?
291.110 Who may BSEE require to produce information?
291.111 How does BSEE treat the confidential information I provide?
291.112 What process will BSEE follow in rendering a decision on 
whether a grantee or transporter has provided open and 
nondiscriminatory access?
291.113 What actions may BSEE take to remedy denial of open and 
nondiscriminatory access?
291.114 How do I appeal to the IBLA?
291.115 How do I exhaust administrative remedies?

    Authority: 31 U.S.C. 9701, 43 U.S.C. 1334.

Sec.  291.1  What is BSEE's authority to collect information?

    (a) The Office of Management and Budget (OMB) has approved the 
information collection requirements in this part under 44 U.S.C. 3501 
et seq., and assigned OMB Control Number 1010-0172.
    (b) An agency may not conduct or sponsor, and you are not required 
to respond to, a collection of information unless it displays a 
currently valid OMB control number.
    (c) We use the information collected to determine whether or not 
the shipper has been denied open and nondiscriminatory access to Outer 
Continental Shelf (OCS) pipelines as sections of 5(e) and (f) of the 
OCS Lands Act (OCSLA) require.
    (d) Respondents are companies that ship or transport oil and gas 
production across the OCS. Responses are required to obtain or retain 
benefits. We will protect information considered proprietary under 
applicable law.
    (e) Send comments regarding any aspect of the collection of 
information under this part, including suggestions for reducing the 
burden, to the Information Collection Clearance Officer, Bureau of 
Safety and Environmental Enforcement, 381 Elden Street, Herndon, VA 
20170.

Sec.  291.100  What is the purpose of this part?

    This part:
    (a) Explains the procedures for filing a complaint with the 
Director, Bureau of Safety and Environmental Enforcement (BSEE) 
alleging that a grantee or transporter has denied a shipper of 
production from the OCS open and nondiscriminatory access to a 
pipeline;
    (b) Explains the procedures BSEE will employ to determine whether 
violations of the requirements of the OCSLA have occurred, and to 
remedy any violations; and
    (c) Provides for alternative informal means of resolving pipeline 
access disputes through either Hotline-assisted procedures or 
alternative dispute resolution (ADR).

Sec.  291.101  What definitions apply to this part?

    As used in this part:
    Accessory means a platform, a major subsea manifold, or similar 
subsea structure attached to a right-of-way (ROW) pipeline to support 
pump stations, compressors, manifolds, etc. The site used for an 
accessory is part of the pipeline ROW grant.
    Appurtenance means equipment, device, apparatus, or other object 
attached to a horizontal component or riser. Examples include anodes, 
valves, flanges, fittings, umbilicals, subsea manifolds, templates, 
pipeline end modules (PLEMs), pipeline end terminals (PLETs), anode 
sleds, other sleds, and jumpers (other than jumpers connecting subsea 
wells to manifolds).
    FERC pipeline means any pipeline within the jurisdiction of the 
Federal Energy Regulatory Commission (FERC) under the Natural Gas Act, 
15 U.S.C. 717-717z, or the Interstate Commerce Act, 42 U.S.C. 7172(a) 
and (b).
    Grantee means any person to whom BSEE has issued an oil or gas 
pipeline permit, license, easement, right-of-way, or other grant of 
authority for transportation on or across the OCS under 30 CFR part 
250, subpart J, or 43 U.S.C. 1337(p), and any person who has an 
assignment of a permit, license, easement, right-of-way or other grant 
of authority, or who has an assignment of any rights subject to any of 
those grants of authority under 30 CFR part 250, subpart J or 43 U.S.C. 
1337(p).
    IBLA means the Interior Board of Land Appeals.
    OCSLA pipeline means any oil or gas pipeline for which BSEE has 
issued a permit, license, easement, right-of-way, or other grant of 
authority.
    Outer Continental Shelf means all submerged lands lying seaward and 
outside of the area of lands beneath navigable waters as defined in 
section 2 of the Submerged Lands Act (43 U.S.C. 1301) and of which the 
subsoil and seabed appertain to the United States and are subject to 
its jurisdiction and control.
    Party means any person who files a complaint, any person who files 
an answer, and BSEE.
    Person means an individual, corporation, government entity, 
partnership, association (including a trust or limited liability 
company), consortium, or joint venture (when established as a separate 
entity).
    Pipeline is the piping, risers, accessories and appurtenances 
installed for transportation of oil and gas.
    Serve means personally delivering a document to a person, or 
sending a document by U.S. mail or private delivery services that 
provide proof of delivery (such as return receipt requested) to a 
person.
    Shipper means a person who contracts or wants to contract with a 
grantee or transporter to transport oil or gas through the grantee's or 
transporter's pipeline.
    Transportation means, for purposes of this part only, the movement 
of oil or gas through an OCSLA pipeline.
    Transporter means, for purposes of this part only, any person who 
owns or operates an OCSLA oil or gas pipeline.

Sec.  291.102  May I call the BSEE Hotline to informally resolve an 
allegation that open and nondiscriminatory access was denied?

    Before filing a complaint under Sec.  291.106, you may attempt to 
informally resolve an allegation concerning open and nondiscriminatory 
access by calling the toll-free BSEE Pipeline Open Access Hotline at 1-
888-232-1713.
    (a) BSEE Hotline staff will informally seek information needed to 
resolve the dispute. BSEE Hotline staff will attempt to resolve 
disputes without litigation or other formal proceedings. The Hotline 
staff will not attempt to resolve matters that are before BSEE or FERC 
in docketed proceedings.
    (b) BSEE Hotline staff may provide information to you and give 
informal oral advice. The advice given is not binding on BSEE, the 
Department of the Interior (DOI), or any other person.
    (c) To the extent permitted by law, the BSEE Hotline staff will 
treat all information it obtains as non-public and confidential.
    (d) You may call the BSEE Hotline anonymously.
    (e) If you contact the BSEE Hotline, you may file a complaint under 
this part if discussions assisted by BSEE Hotline staff are 
unsuccessful at resolving the matter.
    (f) You may terminate use of the BSEE Hotline procedure at any 
time.

[[Page 64622]]

Sec.  291.103  May I use alternative dispute resolution (ADR) to 
informally resolve an allegation that open and nondiscriminatory access 
was denied?

    You may ask to use ADR either before or after you file a complaint. 
To make a request, call the BSEE at 1-888-232-1713 or write to us at 
the following address: Director, Bureau of Safety and Environmental 
Enforcement, Attention: Office of Policy Analysis, 1849 C Street, NW., 
Mail Stop 5438, Washington, DC 20240-0001.
    (a) You may request that ADR be administered by:
    (1) A contracted ADR provider agreed to by all parties;
    (2) The Department's Office of Collaborative Action and Dispute 
Resolution (CADR); or
    (3) BSEE staff trained in ADR and certified by the CADR.
    (b) Each party must pay its respective share of all costs and fees 
associated with any contracted or Departmental ADR provider. For 
purposes of this section, BSEE is not a party in an ADR proceeding.

Sec.  291.104  Who may file a complaint or a third-party brief?

    (a) You may file a complaint under this subpart if you are a 
shipper and you believe that you have been denied open and 
nondiscriminatory access to an OCSLA pipeline that is not a FERC 
pipeline.
    (b) Any person that believes its interests may be affected by 
precedents established by adjudication of complaints under this rule 
may submit a brief to BSEE. The brief must be served following the 
procedure set out in Sec.  291.107. After considering the brief, it is 
within BSEE's discretion as to whether BSEE may:
    (1) Address the brief in its decision;
    (2) Not address the brief in its decision; or
    (3) Include the submitter of the brief in the proceeding as a 
party.

Sec.  291.105  What must a complaint contain?

    For purposes of this subpart, a complaint means a comprehensive 
written brief stating the legal and factual basis for the allegation 
that a shipper was denied open and nondiscriminatory access, together 
with supporting material. A complaint must:
    (a) Clearly identify the action or inaction which is alleged to 
violate 43 U.S.C. 1334(e) or (f)(1)(A);
    (b) Explain how the action or inaction violates 43 U.S.C. 1334(e) 
or (f)(1)(A);
    (c) Explain how the action or inaction affects your interests, 
including practical, operational, or other non-financial impacts;
    (d) Estimate any financial impact or burden;
    (e) State the specific relief or remedy requested; and
    (f) Include all documents that support the facts in your complaint 
including, but not limited to, contracts and any affidavits that may be 
necessary to support particular factual allegations.

Sec.  291.106  How do I file a complaint?

    To file a complaint under this part, you must:
    (a) File your complaint with the Director, Bureau of Safety and 
Environmental Enforcement at the following address: Director, Bureau of 
Safety and Environmental Enforcement, Attention: Office of Policy 
Analysis, 1849 C Street, NW., Mail Stop 5438, Washington, DC 20240-
0001; and
    (b) Include a nonrefundable processing fee of $7,500 under Sec.  
291.108(a) or a request for reduction or waiver of the fee under Sec.  
291.109(a); and
    (c) Serve your complaint on all persons named in the complaint. If 
you make a claim under Sec.  291.111 for confidentiality, serve the 
redacted copy and proposed form of a protective agreement on all 
persons named in the complaint.
    (d) Complaints shall not be filed later than 2 years from the time 
of the alleged access denial. If the complaint is filed later than 2 
years from the time of the alleged access denial, the BSEE Director 
will not consider the complaint and the case will be closed.

Sec.  291.107  How do I answer a complaint?

    (a) If you have been served a complaint under Sec.  291.106, you 
must file an answer within 60 days of receiving the complaint. If you 
miss this deadline, BSEE may disregard your answer. We consider your 
answer to be filed when the BSEE Director receives it at the following 
address: Director, Bureau of Safety and Environmental Enforcement, 
Attention: Office of Policy Analysis, 1849 C Street, NW., Mail Stop 
5438, Washington, DC 20240-0001.
    (b) For purposes of this paragraph, an answer means a comprehensive 
written brief stating the legal and factual basis refuting the 
allegations in the complaint, together with supporting material. You 
must:
    (1) Attach to your answer a copy of the complaint or reference the 
assigned BSEE docket number (you may obtain the docket number by 
calling the Office of Policy Analysis at (202) 208-3530);
    (2) Explain in your answer why the action or inaction alleged in 
the complaint does not violate 43 U.S.C. 1334(e) or (f)(1)(A);
    (3) Include with your answer all documents in your possession or 
that you can otherwise obtain that support the facts in your answer 
including, but not limited to, contracts and any affidavits that may be 
necessary to support particular factual allegations; and
    (4) Provide a copy of your answer to all parties named in the 
complaint including the complainant. If you make a claim under Sec.  
291.111 for confidentiality, serve the redacted copy and proposed form 
of a protective agreement to all parties named in the complaint, 
including the complainant.

Sec.  291.108  How do I pay the processing fee?

    (a) You must pay the processing fee electronically through Pay.Gov. 
The Pay.Gov Web site may be accessed through links on the BSEE Offshore 
Web site at: http://www.bsee.gov/offshore/homepage (on drop-down topic 
list) or directly through Pay.Gov at: https://www.pay.gov/paygov/.
    (b) You must include with the payment:
    (1) Your taxpayer identification number;
    (2) Your payor identification number, if applicable; and
    (3) The complaint caption, or any other applicable identification 
of the complaint you are filing.

Sec.  291.109  Can I ask for a fee waiver or a reduced processing fee?

    (a) BSEE may grant a fee waiver or fee reduction in extraordinary 
circumstances. You may request a waiver or reduction of your fee by:
    (1) Sending a written request to the BSEE Office of Policy Analysis 
when you file your complaint; and
    (2) Demonstrating in your request that you are unable to pay the 
fee or that payment of the full fee would impose an undue hardship upon 
you.
    (b) The BSEE Office of Policy Analysis will send you a written 
decision granting or denying your request for a fee waiver or a fee 
reduction.
    (1) If we grant your request for a fee reduction, you must pay the 
reduced processing fee within 30 days of the date you receive our 
decision.
    (2) If we deny your request, you must pay the entire processing fee 
within 30 days of the date you receive the decision.
    (3) BSEE's decision granting or denying a fee waiver or reduction 
is final for the Department.

Sec.  291.110  Who may BSEE require to produce information?

    (a) BSEE may require any lessee, operator of a lease or unit, 
shipper, grantee, or transporter to provide

[[Page 64623]]

information that BSEE believes is necessary to make a decision on 
whether open access or nondiscriminatory access was denied.
    (b) If you are a party and fail to provide information BSEE 
requires under paragraph (a) of this section, BSEE may:
    (1) Assess civil penalties under 30 CFR part 250, subpart N;
    (2) Dismiss your complaint or consider your answer incomplete; or
    (3) Presume the required information is adverse to you on the 
factual issues to which the information is relevant.
    (c) If you are not a party to a complaint and fail to provide 
information BSEE requires under paragraph (a) of this section, BSEE may 
assess civil penalties under 30 CFR part 250, subpart N.

Sec.  291.111  How does BSEE treat the confidential information I 
provide?

    (a) Any person who provides documents under this part in response 
to a request by BSEE to inform a decision on whether open access or 
nondiscriminatory access was denied may claim that some or all of the 
information contained in a particular document is confidential. If you 
claim confidential treatment, then when you provide the document to 
BSEE you must:
    (1) Provide a complete unredacted copy of the document and indicate 
on that copy that you are making a request for confidential treatment 
for some or all of the information in the document.
    (2) Provide a statement specifying the specific statutory 
justification for nondisclosure of the information for which you claim 
confidential treatment. General claims of confidentiality are not 
sufficient. You must furnish sufficient information for BSEE to make an 
informed decision on the request for confidential treatment.
    (3) Provide a second copy of the document from which you have 
redacted the information for which you wish to claim confidential 
treatment. If you do not submit a second copy of the document with the 
confidential information redacted, BSEE may assume that there is no 
objection to public disclosure of the document in its entirety.
    (b) In making data and information you submit available to the 
public, BSEE will not disclose documents exempt from disclosure under 
the Freedom of Information Act (5 U.S.C. 552) and will follow the 
procedures set forth in the implementing regulations at 43 CFR part 2 
to give submitters an opportunity to object to disclosure.
    (c) BSEE retains the right to make the determination with regard to 
any claim of confidentiality. BSEE will notify you of its decision to 
deny a claim, in whole or in part, and, to the extent permitted by law, 
will give you an opportunity to respond at least 10 days before its 
public disclosure.

Sec.  291.112  What process will BSEE follow in rendering a decision on 
whether a grantee or transporter has provided open and 
nondiscriminatory access?

    BSEE will begin processing a complaint upon receipt of a processing 
fee or granting a waiver of the fee. The BSEE Director will review the 
complaint, answer, and other information, and will serve all parties 
with a written decision that:
    (a) Makes findings of fact and conclusions of law; and
    (b) Renders a decision determining whether the complainant has been 
denied open and nondiscriminatory access.

Sec.  291.113  What actions may BSEE take to remedy denial of open and 
nondiscriminatory access?

    If the BSEE Director's decision under Sec.  291.112 determines that 
the grantee or transporter has not provided open access or 
nondiscriminatory access, then the decision will describe the actions 
BSEE will take to require the grantee or transporter to remedy the 
denial of open access or nondiscriminatory access. The remedies BSEE 
would require must be consistent with BSEE's statutory authority, 
regulations, and any limits thereon due to Congressional delegations to 
other agencies. Actions BSEE may take include, but are not limited to:
    (a) Ordering grantees and transporters to provide open and 
nondiscriminatory access to the complainant;
    (b) Assessing civil penalties of up to $10,000 per day under 30 CFR 
part 250, subpart N, for failure to comply with a BSEE order to provide 
open access or nondiscriminatory access. Penalties will begin to accrue 
60 days after the grantee or transporter receives the order to provide 
open and nondiscriminatory access if it has not provided such access by 
that time. However, if BSEE determines that requiring the construction 
of facilities would be an appropriate remedy under the OCSLA, penalties 
will begin to accrue 10 days after conclusion of diligent construction 
of needed facilities or 60 days after the grantee or transporter 
receives the order to provide open and nondiscriminatory access, 
whichever is later, if it has not provided such access by that time;
    (c) Requesting the Attorney General to institute a civil action in 
the appropriate United States District Court under 43 U.S.C. 1350(a) 
for a temporary restraining order, injunction, or other appropriate 
remedy to enforce the open and nondiscriminatory access requirements of 
43 U.S.C. 1334(e) and (f)(1)(A); or
    (d) Initiating a proceeding to forfeit the right-of-way grant under 
43 U.S.C. 1334(e).

Sec.  291.114  How do I appeal to the IBLA?

    Any party, except as provided in Sec.  291.115(b), adversely 
affected by a decision of the BSEE Director under this part may appeal 
to the Interior Board of Land Appeals (IBLA) under the procedures in 43 
CFR part 4, subpart E.

Sec.  291.115  How do I exhaust administrative remedies?

    (a) If the BSEE Director issues a decision under this part but does 
not expressly make the decision effective upon issuance, you must 
appeal the decision to the IBLA under 43 CFR part 4 to exhaust 
administrative remedies. Such decision will not be effective during the 
time in which a person adversely affected by the BSEE Director's 
decision may file a notice of appeal with the IBLA, and the timely 
filing of a notice of appeal will suspend the effect of the decision 
pending the decision on appeal.
    (b) This section does not apply if a decision was made effective 
by:
    (1) The BSEE Director; or
    (2) The Assistant Secretary for Land and Minerals Management.

0
2. Add chapter V to read as follows:

CHAPTER V--BUREAU OF OCEAN ENERGY MANAGMENT, DEPARTMENT OF THE INTERIOR

SUBCHAPTER A--MINERALS REVENUE MANAGEMENT

Part
519 DISTRIBUTION AND DISBURSEMENT OF ROYALTIES, RENTALS, AND BONUSES

SUBCHAPTER B--OFFSHORE

550 OIL AND GAS AND SULPHUR OPERATIONS IN THE OUTER CONTINENTAL 
SHELF
551 GEOLOGICAL AND GEOPHYSICAL (G&G) EXPLORATIONS OF THE OUTER 
CONTINENTAL SHELF
552 OUTER CONTINENTAL SHELF (OCS) OIL AND GAS INFORMATION PROGRAM
553 OIL SPILL FINANCIAL RESPONSIBILITY FOR OFFSHORE FACILITIES
556 LEASING OF SULPHUR OR OIL AND GAS IN THE OUTER CONTINENTAL SHELF
559 MINERAL LEASING: DEFINITIONS
560 OUTER CONTINENTAL SHELF OIL AND GAS LEASING

[[Page 64624]]

570 NONDISCRIMINATION IN THE OUTER CONTINENTAL SHELF
580 PROSPECTING FOR MINERALS OTHER THAN OIL, GAS, AND SULPHUR ON THE 
OUTER CONTINENTAL SHELF
581 LEASING OF MINERALS OTHER THAN OIL, GAS, AND SULPHUR IN THE 
OUTER CONTINENTAL SHELF
582 OPERATIONS IN THE OUTER CONTINENTAL SHELF FOR MINERALS OTHER 
THAN OIL, GAS, AND SULPHUR
585 RENEWABLE ENERGY AND ALTERNATE USES OF EXISTING FACILITIES ON 
THE OUTER CONTINENTAL SHELF

SUBCHAPTER C--APPEALS

590 APPEAL PROCEDURES

SUBCHAPTER A--MINERALS REVENUE MANAGEMENT

PART 519--DISTRIBUTION AND DISBURSEMENT OF ROYALTIES, RENTALS, AND 
BONUSES

Subpart A--General Provisions [Reserved]
Subpart B--Oil and Gas, General [Reserved]
Subpart C--[Reserved]
Subpart D--Oil and Gas, Offshore
Sec.
519.410 What does this subpart contain?
519.411 What definitions apply to this subpart?
519.412 How will the qualified OCS revenues be divided?
519.413 How will the coastal political subdivisions of Gulf 
producing States share in the qualified OCS revenues?
519.414 How will BOEM determine each Gulf producing State's share of 
the qualified OCS revenues?
519.415 How will bonus and royalty credits affect revenues allocated 
to Gulf producing States?
519.416 How will the qualified OCS revenues be allocated to coastal 
political subdivisions within the Gulf producing States?
519.417 How will BOEM calculate the percentage allocation of 
qualified OCS revenues to the coastal political subdivisions if, 
during any fiscal year, there are no applicable leased tracts in the 
181 Area in the Eastern Gulf of Mexico Planning Area?
519.418 When will funds be disbursed to Gulf producing States and 
eligible coastal political subdivisions?

    Authority: Section 104, Pub. L. 97-451, 96 Stat. 2451 (30 U.S.C. 
1714), Pub. L. 109-432, Div C, Title I, 120 Stat. 3000.

Subpart A--General Provisions [Reserved]

Subpart B--Oil and Gas, General [Reserved]

Subpart C--[Reserved]

Subpart D--Oil and Gas, Offshore

Sec.  519.410  What does this subpart contain?

    (a) The Gulf of Mexico Energy Security Act of 2006 (GOMESA) directs 
the Secretary of the Interior to disburse a portion of the rentals, 
royalties, bonus, and other sums derived from certain Outer Continental 
Shelf (OCS) leases in the Gulf of Mexico (GOM) to the States of 
Alabama, Louisiana, Mississippi, and Texas (collectively identified as 
the Gulf producing States); to eligible coastal political subdivisions 
within those States; and to the Land and Water Conservation Fund. 
Shared GOMESA revenues are reserved for the following purposes:
    (1) Projects and activities for the purposes of coastal protection, 
including conservation, coastal restoration, hurricane protection, and 
infrastructure directly affected by coastal wetland losses.
    (2) Mitigation of damage to fish, wildlife, or natural resources.
    (3) Implementation of a federally-approved marine, coastal, or 
comprehensive conservation management plan.
    (4) Mitigation of the impact of OCS activities through the funding 
of onshore infrastructure projects.
    (5) Planning assistance and administrative costs not-to-exceed 3 
percent of the amounts received.
    (b) This subpart sets forth the formula and methodology BOEM will 
use to determine the amount of revenues to be disbursed and the amount 
to be allocated to each Gulf producing State and each eligible coastal 
political subdivision. For questions related to the revenue sharing 
provisions in this subpart, please contact: Program Manager, Financial 
Management; Office of Natural Resources Revenue; P.O. Box 25165; Denver 
Federal Center, Building 85; MS-61210B; Denver, CO 80225-0165, or at 
(303) 231-3435.

Sec.  519.411  What definitions apply to this subpart?

    Terms in this subpart have the following meaning:
    181 Area means the area identified in map 15, page 58, of the 
Proposed Final Outer Continental Shelf Oil and Gas Leasing Program for 
1997-2002, dated August 1996, of the Bureau of Ocean Energy Management, 
available in the Office of the Director of the Bureau of Ocean Energy 
Management, excluding the area offered in OCS Lease Sale 181, held on 
December 5, 2001.
    181 Area in the Eastern Planning Area is comprised of the area of 
overlap of the two geographic areas defined as the ``181 Area'' and the 
``Eastern Planning Area.''
    181 South Area means any area--
    (1) Located:
    (i) South of the 181 Area;
    (ii) West of the Military Mission Line; and
    (iii) In the Central Planning Area;
    (2) Excluded from the Proposed Final Outer Continental Shelf Oil 
and Gas Leasing Program for 1997-2002, dated August 1996, of the Bureau 
of Ocean Energy Management; and
    (3) Included in the areas considered for oil and gas leasing, as 
identified in map 8, page 37, of the document entitled, Draft Proposed 
Program Outer Continental Shelf Oil and Gas Leasing Program 2007-2012, 
dated February 2006.
    Applicable leased tract means a tract that is subject to a lease 
under section 8 of the Outer Continental Shelf Lands Act for the 
purpose of drilling for, developing, and producing oil or natural gas 
resources, and is located fully or partially in either the 181 Area in 
the Eastern Planning Area, or in the 181 South Area.
    Central Planning Area means the Central Gulf of Mexico Planning 
Area of the Outer Continental Shelf, as designated in the document 
entitled, Draft Proposed Program Outer Continental Shelf Oil and Gas 
Leasing Program 2007-2012, dated February 2006.
    Coastal political subdivision means a political subdivision of a 
Gulf producing State any part of which political subdivision is:
    (1) Within the coastal zone (as defined in section 304 of the 
Coastal Zone Management Act of 1972 (16 U.S.C. 1453)) of the Gulf 
producing State as of December 20, 2006; and
    (2) Not more than 200 nautical miles from the geographic center of 
any leased tract.
    Coastline means the line of ordinary low water along that portion 
of the coast which is in direct contact with the open sea and the line 
marking the seaward limit of inland waters. This is the same definition 
used in section 2 of the Submerged Lands Act (43 U.S.C. 1301).
    Distance means the minimum great circle distance.
    Eastern Planning Area means the Eastern Gulf of Mexico Planning 
Area of the Outer Continental Shelf, as designated in the document 
entitled,

[[Page 64625]]

Draft Proposed Program Outer Continental Shelf Oil and Gas Leasing 
Program 2007-2012, dated February 2006.
    Gulf producing State means each of the States of Alabama, 
Louisiana, Mississippi, and Texas.
    Leased tract means any tract that is subject to a lease under 
section 6 or 8 of the Outer Continental Shelf Lands Act for the purpose 
of drilling for, developing, and producing oil or natural gas 
resources.
    Military Mission Line means the north-south line at 86[deg]41' W. 
longitude.
    Qualified OCS revenues mean:
    (1) The term qualified OCS revenues means, in the case of each of 
fiscal years 2007 through 2016, all rentals, royalties, bonus bids, and 
other sums received by the U.S. from leases entered into on or after 
December 20, 2006, located:
    (i) In the 181 Area in the Eastern Planning Area; and
    (ii) In the 181 South Area.
    (iii) For applicable leased tracts intersected by the planning area 
administrative boundary line (e.g., separating the GOM Central Planning 
Area from the Eastern Planning Area), only the percent of revenues 
equivalent to the percent of surface acreage in the 181 Area in the 
Eastern Planning Area will be considered qualified OCS revenues.
    (2) Exclusions to the term qualified OCS revenues include:
    (i) Revenues from the forfeiture of a bond or other surety securing 
obligations other than royalties;
    (ii) Civil penalties;
    (iii) Royalties taken by the Secretary in-kind and not sold;
    (iv) User fees; and
    (v) Lease revenues explicitly circumscribed from GOMESA revenue 
sharing by statute or appropriations law.

Sec.  519.412  How will the qualified OCS revenues be divided?

    For each of the fiscal years 2007 through 2016, 50 percent of the 
qualified OCS revenues will be placed in a special U.S. Treasury 
account from which 75 percent of the revenues will be disbursed to the 
Gulf producing States, and 25 percent will be disbursed to the Land and 
Water Conservation Fund. Each Gulf producing State will receive at 
least 10 percent of the qualified OCS revenues available for allocation 
to the Gulf producing States each fiscal year.

       Revenue Distribution of Qualified OCS Revenues Under GOMESA
------------------------------------------------------------------------
                                                           Percentage of
                                                           qualified OCS
           Recipient of qualified OCS revenues               revenues
                                                             (percent)
------------------------------------------------------------------------
U.S. Treasury (General Fund)............................           50
Land and Water Conservation Fund........................           12.5
Gulf Producing States...................................           30
Gulf Producing State Coastal Political Subdivisions.....            7.5
------------------------------------------------------------------------

Sec.  519.413  How will the coastal political subdivisions of Gulf 
producing States share in the qualified OCS revenues?

    Of the revenues allocated to a Gulf producing State, 20 percent 
will be distributed to the coastal political subdivisions within that 
State.

Sec.  519.414  How will BOEM determine each Gulf producing State's 
share of the qualified OCS revenues?

    (a) BOEM will determine the geographic centers of each applicable 
leased tract and, using the great circle distance method, will 
determine the closest distance from the geographic centers of each 
applicable leased tract to each Gulf producing State's coastline.
    (b) Based on these distances, we will calculate the qualified OCS 
revenues to be disbursed to each Gulf producing State using the 
following procedure:
    (1) For each Gulf producing State, we will calculate and total, 
over all applicable leased tracts, the mathematical inverses of the 
distances between the points on the State's coastline that are closest 
to the geographic centers of the applicable leased tracts and the 
geographic centers of the applicable leased tracts. For applicable 
leased tracts intersected by the planning area administrative boundary 
line, the geographic center used for the inverse distance determination 
will be the geographic center of the entire lease as if it were not 
intersected.
    (2) For each Gulf producing State, we will divide the sum of each 
State's inverse distances, from all applicable leased tracts, by the 
sum of the inverse distances from all applicable leased tracts across 
all four Gulf producing States. We will multiply the result by the 
amount of qualified OCS revenues to be shared as shown below. In the 
formulas, IAL, ILA, IMS, and ITX represent the sum of the inverses of 
the closest distances between Alabama, Louisiana, Mississippi, and 
Texas and all applicable leased tracts, respectively.

Alabama Share = (IAL / (IAL + ILA + IMS + ITX)) x Qualified OCS 
Revenues
Louisiana Share = (ILA / (IAL + ILA + IMS + ITX)) x Qualified OCS 
Revenues
Mississippi Share = (IMS / (IAL + ILA + IMS + ITX)) x Qualified OCS 
Revenues
Texas Share = (ITX / (IAL + ILA + IMS + ITX)) x Qualified OCS Revenues

    (3) If in any fiscal year, this calculation results in less than a 
10 percent allocation of the qualified OCS revenues to any Gulf 
producing State, we will recalculate the distribution. We will allocate 
10 percent of the qualified OCS revenues to the State and recalculate 
the other States' shares of the remaining qualified OCS revenues 
omitting the State receiving the 10 percent minimum share and its 10 
percent share from the calculation.

Sec.  519.415  How will bonus and royalty credits affect revenues 
allocated to Gulf producing States?

    If bonus and royalty credits issued under Section 104(c) of the 
Gulf of Mexico Energy Security Act are used to pay bonuses or royalties 
on leases in the 181 Area located in the Eastern Planning Area and the 
181 South Area, then there will be a corresponding reduction in 
qualified OCS revenues available for distribution.

Sec.  519.416  How will the qualified OCS revenues be allocated to 
coastal political subdivisions within the Gulf producing States?

    BOEM will calculate the percentage allocation of funds to the 
coastal political subdivisions in accordance with the following 
criteria:
    (a) Twenty-five percent of the qualified OCS revenues will be 
allocated to a Gulf producing State's coastal political subdivisions in 
the proportion that each coastal political subdivision's population 
bears to the population of all coastal political subdivisions in the 
producing State;
    (b) Twenty-five percent of the qualified OCS revenues will be 
allocated to a Gulf producing State's coastal political subdivisions in 
the proportion that each coastal political subdivision's miles of 
coastline bears to the number of miles of coastline of all coastal 
political subdivisions in the producing State. Except that, for the 
State of Louisiana, proxy coastline lengths for coastal political 
subdivisions without a coastline will be considered to be \1/3\ the 
average length of the coastline of all political subdivisions within 
Louisiana having a coastline.
    (c) Fifty percent of the revenues will be allocated to a Gulf 
producing State's

[[Page 64626]]

coastal political subdivisions in amounts that are inversely 
proportional to the respective distances between the geographic center 
of each applicable leased tract and the point in each coastal political 
subdivision that is closest to the geographic center of each applicable 
leased tract. Except that, an applicable leased tract will be excluded 
from this calculation if any portion of the tract is located in a 
geographic area that was subject to a leasing moratorium on January 1, 
2005, unless that tract was in production on that date.

Sec.  519.417  How will BOEM calculate the percentage allocation of 
qualified OCS revenues to the coastal political subdivisions if, during 
any fiscal year, there are no applicable leased tracts in the 181 Area 
in the Eastern Gulf of Mexico Planning Area?

    If, during any fiscal year, there are no applicable leased tracts 
in the 181 Area in the Eastern Gulf of Mexico Planning Area, BOEM will 
calculate the percentage allocation of funds to the coastal political 
subdivisions in accordance with the following criteria:
    (a) Fifty percent of the revenues will be allocated to a Gulf 
producing State's coastal political subdivisions in the proportion that 
each coastal political subdivision's population bears to the population 
of all coastal political subdivisions in the State; and
    (b) Fifty percent of the revenues will be allocated to a Gulf 
producing State's coastal political subdivisions in the proportion that 
each coastal political subdivision's miles of coastline bears to the 
number of miles of coastline of all coastal political subdivisions in 
the State. Except that, for the State of Louisiana, proxy coastline 
lengths for coastal political subdivisions without a coastline will be 
considered to be \1/3\ the average length of the coastline of all 
political subdivisions within Louisiana having a coastline.

Sec.  519.418  When will funds be disbursed to Gulf producing States 
and eligible coastal political subdivisions?

    (a) The Office of Natural Resources Revenue (ONRR) will disburse 
allocated funds in the fiscal year after it collects the qualified OCS 
revenues. For example, ONRR will disburse funds in fiscal year 2010 
from the qualified OCS revenues collected during fiscal year 2009.
    (b) ONRR intends to disburse funds on or before March 31st of the 
year following the fiscal year of qualified OCS revenues.

Subchapter B--OFFSHORE

PART 550--OIL AND GAS AND SULPHUR OPERATIONS IN THE OUTER 
CONTINENTAL SHELF

Subpart A--General

Authority and Definition of Terms

Sec.
550.101 Authority and applicability.
550.102 What does this part do?
550.103 Where can I find more information about the requirements in 
this part?
550.104 How may I appeal a decision made under BOEM regulations?
550.105 Definitions.

Performance Standards

550.115 How do I determine well producibility?
550.116 How do I determine producibility if my well is in the Gulf 
of Mexico?
550.117 How does a determination of well producibility affect 
royalty status?
550.118 [Reserved]
550.119 Will BOEM approve subsurface gas storage?
550.120-550.121 [Reserved]
550.122 What effect does subsurface storage have on the lease term?
550.123 Will BOEM allow gas storage on unleased lands?

Fees

550.125 Service fees.
550.126 Electronic payment instructions.

Inspection of Operations

550.130 [Reserved]

Disqualification

550.135 What will BOEM do if my operating performance is 
unacceptable?
550.136 How will BOEM determine if my operating performance is 
unacceptable?

Special Types of Approvals

550.140 When will I receive an oral approval?
550.141 May I ever use alternate procedures or equipment?
550.142 How do I receive approval for departures?
550.143 How do I designate an operator?
550.144 How do I designate a new operator when a designation of 
operator terminates?
550.145 How do I designate an agent or a local agent?
550.146 Who is responsible for fulfilling leasehold obligations?

Right-of-Use and Easement

550.160 When will BOEM grant me a right-of-use and easement, and 
what requirements must I meet?
550.161 What else must I submit with my application?
550.162 May I continue my right-of-use and easement after the 
termination of any lease on which it is situated?
550.163 If I have a State lease, will BOEM grant me a right-of-use 
and easement?
550.164 If I have a State lease, what conditions apply for a right-
of-use and easement?
550.165 If I have a State lease, what fees do I have to pay for a 
right-of-use and easement?
550.166 If I have a State lease, what surety bond must I have for a 
right-of-use and easement?

Primary Lease Requirements, Lease Term Extensions, and Lease 
Cancellations

550.181 When may the Secretary cancel my lease and when am I 
compensated for cancellation?
550.182 When may the Secretary cancel a lease at the exploration 
stage?
550.183 When may BOEM or the Secretary extend or cancel a lease at 
the development and production stage?
550.184 What is the amount of compensation for lease cancellation?
550.185 When is there no compensation for a lease cancellation?

Information and Reporting Requirements

550.186 What reporting information and report forms must I submit?
550.187-550.193 [Reserved]
550.194 How must I protect archaeological resources?
550.195 [Reserved]
550.196 Reimbursements for reproduction and processing costs.
550.197 Data and information to be made available to the public or 
for limited inspection.

References

550.198 [Reserved]
550.199 Paperwork Reduction Act statements--information collection.
Subpart B--Plans and Information

General Information

550.200 Definitions.
550.201 What plans and information must I submit before I conduct 
any activities on my lease or unit?
550.202 What criteria must the Exploration Plan (EP), Development 
and Production Plan (DPP), or Development Operations Coordination 
Document (DOCD) meet?
550.203 Where can wells be located under an EP, DPP, or DOCD?
550.204-550.205 [Reserved]
550.206 How do I submit the EP, DPP, or DOCD?

Ancillary Activities

550.207 What ancillary activities may I conduct?
550.208 If I conduct ancillary activities, what notices must I 
provide?
550.209 What is the BOEM review process for the notice?
550.210 If I conduct ancillary activities, what reporting and data/
information retention requirements must I satisfy?

Contents of Exploration Plans (EP)

550.211 What must the EP include?
550.212 What information must accompany the EP?
550.213 What general information must accompany the EP?
550.214 What geological and geophysical (G&G) information must 
accompany the EP?

[[Page 64627]]

550.215 What hydrogen sulfide (H2S) information must 
accompany the EP?
550.216 What biological, physical, and socioeconomic information 
must accompany the EP?
550.217 What solid and liquid wastes and discharges information and 
cooling water intake information must accompany the EP?
550.218 What air emissions information must accompany the EP?
550.219 What oil and hazardous substance spills information must 
accompany the EP?
550.220 If I propose activities in the Alaska OCS Region, what 
planning information must accompany the EP?
550.221 What environmental monitoring information must accompany the 
EP?
550.222 What lease stipulations information must accompany the EP?
550.223 What mitigation measures information must accompany the EP?
550.224 What information on support vessels, offshore vehicles, and 
aircraft you will use must accompany the EP?
550.225 What information on the onshore support facilities you will 
use must accompany the EP?
550.226 What Coastal Zone Management Act (CZMA) information must 
accompany the EP?
550.227 What environmental impact analysis (EIA) information must 
accompany the EP?
550.228 What administrative information must accompany the EP?

Review and Decision Process for the EP

550.231 After receiving the EP, what will BOEM do?
550.232 What actions will BOEM take after the EP is deemed 
submitted?
550.233 What decisions will BOEM make on the EP and within what 
timeframe?
550.234 How do I submit a modified EP or resubmit a disapproved EP, 
and when will BOEM make a decision?
550.235 If a State objects to the EP's coastal zone consistency 
certification, what can I do?

Contents of Development and Production Plans (DPP) and Development 
Operations Coordination Documents (DOCD)

550.241 What must the DPP or DOCD include?
550.242 What information must accompany the DPP or DOCD?
550.243 What general information must accompany the DPP or DOCD?
550.244 What geological and geophysical (G&G) information must 
accompany the DPP or DOCD?
550.245 What hydrogen sulfide (H2S) information must 
accompany the DPP or DOCD?
550.246 What mineral resource conservation information must 
accompany the DPP or DOCD?
550.247 What biological, physical, and socioeconomic information 
must accompany the DPP or DOCD?
550.248 What solid and liquid wastes and discharges information and 
cooling water intake information must accompany the DPP or DOCD?
550.249 What air emissions information must accompany the DPP or 
DOCD?
550.250 What oil and hazardous substance spills information must 
accompany the DPP or DOCD?
550.251 If I propose activities in the Alaska OCS Region, what 
planning information must accompany the DPP?
550.252 What environmental monitoring information must accompany the 
DPP or DOCD?
550.253 What lease stipulations information must accompany the DPP 
or DOCD?
550.254 What mitigation measures information must accompany the DPP 
or DOCD?
550.255 What decommissioning information must accompany the DPP or 
DOCD?
550.256 What related facilities and operations information must 
accompany the DPP or DOCD?
550.257 What information on the support vessels, offshore vehicles, 
and aircraft you will use must accompany the DPP or DOCD?
550.258 What information on the onshore support facilities you will 
use must accompany the DPP or DOCD?
550.259 What sulphur operations information must accompany the DPP 
or DOCD?
550.260 What Coastal Zone Management Act (CZMA) information must 
accompany the DPP or DOCD?
550.261 What environmental impact analysis (EIA) information must 
accompany the DPP or DOCD?
550.262 What administrative information must accompany the DPP or 
DOCD?

Review and Decision Process for the DPP or DOCD

550.266 After receiving the DPP or DOCD, what will BOEM do?
550.267 What actions will BOEM take after the DPP or DOCD is deemed 
submitted?
550.268 How does BOEM respond to recommendations?
550.269 How will BOEM evaluate the environmental impacts of the DPP 
or DOCD?
550.270 What decisions will BOEM make on the DPP or DOCD and within 
what timeframe?
550.271 For what reasons will BOEM disapprove the DPP or DOCD?
550.272 If a State objects to the DPP's or DOCD's coastal zone 
consistency certification, what can I do?
550.273 How do I submit a modified DPP or DOCD or resubmit a 
disapproved DPP or DOCD?

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

550.280 How must I conduct activities under the approved EP, DPP, or 
DOCD?
550.281 What must I do to conduct activities under the approved EP, 
DPP, or DOCD?
550.282 Do I have to conduct post-approval monitoring?
550.283 When must I revise or supplement the approved EP, DPP, or 
DOCD?
550.284 How will BOEM require revisions to the approved EP, DPP, or 
DOCD?
550.285 How do I submit revised and supplemental EPs, DPPs, and 
DOCDs?

Conservation Information Documents (CID)

550.296 When and how must I submit a CID or a revision to a CID?
550.297 What information must a CID contain?
550.298 How long will BOEM take to evaluate and make a decision on 
the CID?
550.299 What operations require approval of the CID?
Subpart C--Pollution Prevention and Control
550.300 [Reserved]
550.301 [Reserved]
550.302 Definitions concerning air quality.
550.303 Facilities described in a new or revised Exploration Plan or 
Development and Production Plan.
550.304 Existing facilities.
Subpart D--[Reserved]
Subpart E--[Reserved]
Subpart F--[Reserved]
Subpart G--[Reserved]
Subpart H--[Reserved]
Subpart I--[Reserved]
Subpart J--Pipelines and Pipeline Rights of Way
550.1011 Bond requirements for pipeline right-of-way holders.
Subpart K--Oil and Gas Production Requirements

Well Tests and Surveys

550.1153 When must I conduct a static bottomhole pressure survey?

Classifying Reservoirs

550.1154 How do I determine if my reservoir is sensitive?
550.1155 What information must I submit for sensitive reservoirs?

Other Requirements

550.1165 What must I do for enhanced recovery operations?
550.1166 What additional reporting is required for developments in 
the Alaska OCS Region?
550.1167 What information must I submit with forms and for 
approvals?
Subpart L--[Reserved]
Subpart M--[Reserved]
Subpart N--Outer Continental Shelf Civil Penalties

Outer Continental Shelf Lands Act Civil Penalties

550.1400 How does BOEM begin the civil penalty process?
550.1401 Index table.
550.1402 Definitions.
550.1403 What is the maximum civil penalty?
550.1404 Which violations will BOEM review for potential civil 
penalties?

[[Page 64628]]

550.1405 When is a case file developed?
550.1406 When will BOEM notify me and provide penalty information?
550.1407 How do I respond to the letter of notification?
550.1408 When will I be notified of the Reviewing Officer's 
decision?
550.1409 What are my appeal rights?

Federal Oil and Gas Royalty Management Act Civil Penalties Definitions

550.1450 What definitions apply to this subpart?

Penalties After a Period To Correct

550.1451 What may BOEM do if I violate a statute, regulation, order, 
or lease term relating to a Federal oil and gas lease?
550.1452 What if I correct the violation?
550.1453 What if I do not correct the violation?
550.1454 How may I request a hearing on the record on a Notice of 
Noncompliance?
550.1455 Does my request for a hearing on the record affect the 
penalties?
550.1456 May I request a hearing on the record regarding the amount 
of a civil penalty if I did not request a hearing on the Notice of 
Noncompliance?

Penalties Without a Period To Correct

550.1460 May I be subject to penalties without prior notice and an 
opportunity to correct?
550.1461 How will BOEM inform me of violations without a period to 
correct?
550.1462 How may I request a hearing on the record on a Notice of 
Noncompliance regarding violations without a period to correct?
550.1463 Does my request for a hearing on the record affect the 
penalties?
550.1464 May I request a hearing on the record regarding the amount 
of a civil penalty if I did not request a hearing on the Notice of 
Noncompliance?

General Provisions

550.1470 How does BOEM decide what the amount of the penalty should 
be?
550.1471 Does the penalty affect whether I owe interest?
550.1472 How will the Office of Hearings and Appeals conduct the 
hearing on the record?
550.1473 How may I appeal the Administrative Law Judge's decision?
550.1474 May I seek judicial review of the decision of the Interior 
Board of Land Appeals?
550.1475 When must I pay the penalty?
550.1476 Can BOEM reduce my penalty once it is assessed?
550.1477 How may BOEM collect the penalty?

Criminal Penalties

550.1480 May the United States criminally prosecute me for 
violations under Federal oil and gas leases?

Bonding Requirements

550.1490 What standards must my BOEM-specified surety instrument 
meet?
550.1491 How will BOEM determine the amount of my bond or other 
surety instrument?

Financial Solvency Requirements

550.1495 How do I demonstrate financial solvency?
550.1496 How will BOEM determine if I am financially solvent?
550.1497 When will BOEM monitor my financial solvency?
Subpart O--[Reserved]
Subpart P--[Reserved]
Subpart Q--[Reserved]
Subpart R--[Reserved]
Subpart S--[Reserved]

    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.  550.101  Authority and applicability.

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

Sec.  550.102  What does this part do?

    (a) 30 CFR part 550 contains the regulations of the BOEM Offshore 
program that govern oil, gas, and sulphur exploration, development, and 
production operations on the OCS. When you conduct operations on the 
OCS, you must submit requests, applications, and notices, or provide 
supplemental information for BOEM approval.
    (b) The following table of general references shows where to look 
for information about these processes.

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

[[Page 64629]]

Sec.  550.103  Where can I find more information about the requirements 
in this part?

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

Sec.  550.104  How may I appeal a decision made under BOEM regulations?

    To appeal orders or decisions issued under BOEM regulations in 30 
CFR parts 550 to 582, follow the procedures in 30 CFR part 590.

Sec.  550.105  Definitions.

    Terms used in this part will have the meanings given in the Act and 
as defined in this section:
    Act means the OCS Lands Act, as amended (43 U.S.C. 1331 et seq.).
    Affected State means with respect to any program, plan, lease sale, 
or other activity proposed, conducted, or approved under the provisions 
of the Act, any State:
    (1) The laws of which are declared, under section 4(a)(2) of the 
Act, to be the law of the United States for the portion of the OCS on 
which such activity is, or is proposed to be, conducted;
    (2) Which is, or is proposed to be, directly connected by 
transportation facilities to any artificial island or installation or 
other device permanently or temporarily attached to the seabed;
    (3) Which is receiving, or according to the proposed activity, will 
receive oil for processing, refining, or transshipment that was 
extracted from the OCS and transported directly to such State by means 
of vessels or by a combination of means including vessels;
    (4) Which is designated by the Secretary as a State in which there 
is a substantial probability of significant impact on or damage to the 
coastal, marine, or human environment, or a State in which there will 
be significant changes in the social, governmental, or economic 
infrastructure, resulting from the exploration, development, and 
production of oil and gas anywhere on the OCS; or
    (5) In which the Secretary finds that because of such activity 
there is, or will be, a significant risk of serious damage, due to 
factors such as prevailing winds and currents to the marine or coastal 
environment in the event of any oil spill, blowout, or release of oil 
or gas from vessels, pipelines, or other transshipment facilities.
    Air pollutant means any airborne agent or combination of agents for 
which the Environmental Protection Agency (EPA) has established, under 
section 109 of the Clean Air Act, national primary or secondary ambient 
air quality standards.
    Analyzed geological information means data collected under a permit 
or a lease that have been analyzed. Analysis may include, but is not 
limited to, identification of lithologic and fossil content, core 
analysis, laboratory analyses of physical and chemical properties, well 
logs or charts, results from formation fluid tests, and descriptions of 
hydrocarbon occurrences or hazardous conditions.
    Ancillary activities mean those activities on your lease or unit 
that you:
    (1) Conduct to obtain data and information to ensure proper 
exploration or development of your lease or unit; and
    (2) Can conduct without BOEM approval of an application or permit.
    Archaeological interest means capable of providing scientific or 
humanistic understanding of past human behavior, cultural adaptation, 
and related topics through the application of scientific or scholarly 
techniques, such as controlled observation, contextual measurement, 
controlled collection, analysis, interpretation, and explanation.
    Archaeological resource means any material remains of human life or 
activities that are at least 50 years of age and that are of 
archaeological interest.
    Attainment area means, for any air pollutant, an area that is shown 
by monitored data or that is calculated by air quality modeling (or 
other methods determined by the Administrator of EPA to be reliable) 
not to exceed any primary or secondary ambient air quality standards 
established by EPA.
    Best available and safest technology (BAST) means the best 
available and safest technologies that the Director determines to be 
economically feasible wherever failure of equipment would have a 
significant effect on safety, health, or the environment.
    Best available control technology (BACT) means an emission 
limitation based on the maximum degree of reduction for each air 
pollutant subject to regulation, taking into account energy, 
environmental and economic impacts, and other costs. The Regional 
Director will verify the BACT on a case-by-case basis, and it may 
include reductions achieved through the application of processes, 
systems, and techniques for the control of each air pollutant.
    Coastal environment means the physical, atmospheric, and biological 
components, conditions, and factors that interactively determine the 
productivity, state, condition, and quality of the terrestrial 
ecosystem from the shoreline inward to the boundaries of the coastal 
zone.
    Coastal zone means the coastal waters (including the lands therein 
and thereunder) and the adjacent shorelands (including the waters 
therein and thereunder) strongly influenced by each other and in 
proximity to the shorelands of the several coastal States. The coastal 
zone includes islands, transition and intertidal areas, salt marshes, 
wetlands, and beaches. The coastal zone extends seaward to the outer 
limit of the U.S. territorial sea and extends inland from the 
shorelines to the extent necessary to control shorelands, the uses of 
which have a direct and significant impact on the coastal waters, and 
the inward boundaries of which may be identified by the several coastal 
States, under the authority in section 305(b)(1) of the Coastal Zone 
Management Act (CZMA) of 1972.
    Competitive reservoir means a reservoir in which there are one or 
more producible or producing well completions on each of two or more 
leases or portions of leases, with different lease operating interests, 
from which the lessees plan future production.
    Correlative rights when used with respect to lessees of adjacent 
leases, means the right of each lessee to be afforded an equal 
opportunity to explore for, develop, and produce, without waste, 
minerals from a common source.
    Data means facts and statistics, measurements, or samples that have 
not been analyzed, processed, or interpreted.
    Departures mean approvals granted by the appropriate BSEE or BOEM 
representative for operating requirements/procedures other than those 
specified in the regulations found in this part. These requirements/
procedures may be necessary to control a well; properly develop a 
lease; conserve natural resources, or protect life, property, or the 
marine, coastal, or human environment.
    Development means those activities that take place following 
discovery of minerals in paying quantities, including but not limited 
to geophysical activity, drilling, platform construction, and operation 
of all directly related onshore support facilities, and which are for 
the purpose of producing the minerals discovered.
    Development geological and geophysical (G&G) activities means those 
G&G and related data-gathering activities on your lease or unit that 
you conduct following discovery of oil, gas, or sulphur in paying 
quantities to detect

[[Page 64630]]

or imply the presence of oil, gas, or sulphur in commercial quantities.
    Director means the Director of BOEM of the U.S. Department of the 
Interior, or an official authorized to act on the Director's behalf.
    District Manager means the BSEE officer with authority and 
responsibility for operations or other designated program functions for 
a district within a BSEE Region.
    Easement means an authorization for a nonpossessory, nonexclusive 
interest in a portion of the OCS, whether leased or unleased, which 
specifies the rights of the holder to use the area embraced in the 
easement in a manner consistent with the terms and conditions of the 
granting authority.
    Eastern Gulf of Mexico means all OCS areas of the Gulf of Mexico 
the BOEM Director decides are adjacent to the State of Florida. The 
Eastern Gulf of Mexico is not the same as the Eastern Planning Area, an 
area established for OCS lease sales.
    Emission offsets mean emission reductions obtained from facilities, 
either onshore or offshore, other than the facility or facilities 
covered by the proposed Exploration Plan (EP) or Development and 
Production Plan (DPP).
    Enhanced recovery operations mean pressure maintenance operations, 
secondary and tertiary recovery, cycling, and similar recovery 
operations that alter the natural forces in a reservoir to increase the 
ultimate recovery of oil or gas.
    Existing facility, as used in Sec.  550.303, means an OCS facility 
described in an Exploration Plan or a Development and Production Plan 
approved before June 2, 1980.
    Exploration means the commercial search for oil, gas, or sulphur. 
Activities classified as exploration include but are not limited to:
    (1) Geophysical and geological (G&G) surveys using magnetic, 
gravity, seismic reflection, seismic refraction, gas sniffers, coring, 
or other systems to detect or imply the presence of oil, gas, or 
sulphur; and
    (2) Any drilling conducted for the purpose of searching for 
commercial quantities of oil, gas, and sulphur, including the drilling 
of any additional well needed to delineate any reservoir to enable the 
lessee to decide whether to proceed with development and production.
    Facility, as used in Sec.  550.303, means all installations or 
devices permanently or temporarily attached to the seabed. They include 
mobile offshore drilling units (MODUs), even while operating in the 
``tender assist'' mode (i.e., with skid-off drilling units) or other 
vessels engaged in drilling or downhole operations. They are used for 
exploration, development, and production activities for oil, gas, or 
sulphur and emit or have the potential to emit any air pollutant from 
one or more sources. They include all floating production systems 
(FPSs), including column-stabilized-units (CSUs); floating production, 
storage and offloading facilities (FPSOs); tension-leg platforms 
(TLPs); spars, etc. During production, multiple installations or 
devices are a single facility if the installations or devices are at a 
single site. Any vessel used to transfer production from an offshore 
facility is part of the facility while it is physically attached to the 
facility.
    Flaring means the burning of natural gas as it is released into the 
atmosphere.
    Gas reservoir means a reservoir that contains hydrocarbons 
predominantly in a gaseous (single-phase) state.
    Gas-well completion means a well completed in a gas reservoir or in 
the associated gas-cap of an oil reservoir.
    Geological and geophysical (G&G) explorations means those G&G 
surveys on your lease or unit that use seismic reflection, seismic 
refraction, magnetic, gravity, gas sniffers, coring, or other systems 
to detect or imply the presence of oil, gas, or sulphur in commercial 
quantities.
    Governor means the Governor of a State, or the person or entity 
designated by, or under, State law to exercise the powers granted to 
such Governor under the Act.
    H2S absent means:
    (1) Drilling, logging, coring, testing, or producing operations 
have confirmed the absence of H2S in concentrations that 
could potentially result in atmospheric concentrations of 20 ppm or 
more of H2S; or
    (2) Drilling in the surrounding areas and correlation of geological 
and seismic data with equivalent stratigraphic units have confirmed an 
absence of H2S throughout the area to be drilled.
    H2S present means drilling, logging, coring, testing, or producing 
operations have confirmed the presence of H2S in 
concentrations and volumes that could potentially result in atmospheric 
concentrations of 20 ppm or more of H2S.
    H2S unknown means the designation of a zone or geologic formation 
where neither the presence nor absence of H2S has been 
confirmed.
    Human environment means the physical, social, and economic 
components, conditions, and factors that interactively determine the 
state, condition, and quality of living conditions, employment, and 
health of those affected, directly or indirectly, by activities 
occurring on the OCS.
    Interpreted geological information means geological knowledge, 
often in the form of schematic cross sections, 3-dimensional 
representations, and maps, developed by determining the geological 
significance of data and analyzed geological information.
    Interpreted geophysical information means geophysical knowledge, 
often in the form of schematic cross sections, 3-dimensional 
representations, and maps, developed by determining the geological 
significance of geophysical data and analyzed geophysical information.
    Lease means an agreement that is issued under section 8 or 
maintained under section 6 of the Act and that authorizes exploration 
for, and development and production of, minerals. The term also means 
the area covered by that authorization, whichever the context requires.
    Lease term pipelines mean those pipelines owned and operated by a 
lessee or operator that are completely contained within the boundaries 
of a single lease, unit, or contiguous (not cornering) leases of that 
lessee or operator.
    Lessee means a person who has entered into a lease with the United 
States to explore for, develop, and produce the leased minerals. The 
term lessee also includes the BOEM-approved assignee of the lease, and 
the owner or the BOEM-approved assignee of operating rights for the 
lease.
    Major Federal action means any action or proposal by the Secretary 
that is subject to the provisions of section 102(2)(C) of the National 
Environmental Policy Act of 1969, 42 U.S.C. (2)(C) (i.e., an action 
that will have a significant impact on the quality of the human 
environment requiring preparation of an environmental impact statement 
under section 102(2)(C) of the National Environmental Policy Act).
    Marine environment means the physical, atmospheric, and biological 
components, conditions, and factors that interactively determine the 
productivity, state, condition, and quality of the marine ecosystem. 
These include the waters of the high seas, the contiguous zone, 
transitional and intertidal areas, salt marshes, and wetlands within 
the coastal zone and on the OCS.
    Material remains means physical evidence of human habitation, 
occupation, use, or activity, including the site, location, or context 
in which such evidence is situated.

[[Page 64631]]

    Maximum efficient rate (MER) means the maximum sustainable daily 
oil or gas withdrawal rate from a reservoir that will permit economic 
development and depletion of that reservoir without detriment to 
ultimate recovery.
    Maximum production rate (MPR) means the approved maximum daily rate 
at which oil or gas may be produced from a specified oil-well or gas-
well completion.
    Minerals include oil, gas, sulphur, geopressured-geothermal and 
associated resources, and all other minerals that are authorized by an 
Act of Congress to be produced.
    Natural resources include, without limiting the generality thereof, 
oil, gas, and all other minerals, and fish, shrimp, oysters, clams, 
crabs, lobsters, sponges, kelp, and other marine animal and plant life 
but does not include water power or the use of water for the production 
of power.
    Nonattainment area means, for any air pollutant, an area that is 
shown by monitored data or that is calculated by air quality modeling 
(or other methods determined by the Administrator of EPA to be 
reliable) to exceed any primary or secondary ambient air quality 
standard established by EPA.
    Nonsensitive reservoir means a reservoir in which ultimate recovery 
is not decreased by high reservoir production rates.
    Oil reservoir means a reservoir that contains hydrocarbons 
predominantly in a liquid (single-phase) state.
    Oil reservoir with an associated gas cap means a reservoir that 
contains hydrocarbons in both a liquid and gaseous (two-phase) state.
    Oil-well completion means a well completed in an oil reservoir or 
in the oil accumulation of an oil reservoir with an associated gas cap.
    Operating rights mean any interest held in a lease with the right 
to explore for, develop, and produce leased substances.
    Operator means the person the lessee(s) designates as having 
control or management of operations on the leased area or a portion 
thereof. An operator may be a lessee, the BOEM-approved or BSEE-
approved designated agent of the lessee(s), or the holder of operating 
rights under a BOEM-approved operating rights assignment.
    Outer Continental Shelf (OCS) means all submerged lands lying 
seaward and outside of the area of lands beneath navigable waters as 
defined in section 2 of the Submerged Lands Act (43 U.S.C. 1301) whose 
subsoil and seabed appertain to the United States and are subject to 
its jurisdiction and control.
    Person includes a natural person, an association (including 
partnerships, joint ventures, and trusts), a State, a political 
subdivision of a State, or a private, public, or municipal corporation.
    Pipelines are the piping, risers, and appurtenances installed for 
transporting oil, gas, sulphur, and produced waters.
    Processed geological or geophysical information means data 
collected under a permit or a lease that have been processed or 
reprocessed. Processing involves changing the form of data to 
facilitate interpretation. Processing operations may include, but are 
not limited to, applying corrections for known perturbing causes, 
rearranging or filtering data, and combining or transforming data 
elements. Reprocessing is the additional processing other than ordinary 
processing used in the general course of evaluation. Reprocessing 
operations may include varying identified parameters for the detailed 
study of a specific problem area.
    Production means those activities that take place after the 
successful completion of any means for the removal of minerals, 
including such removal, field operations, transfer of minerals to 
shore, operation monitoring, maintenance, and workover operations.
    Production areas are those areas where flammable petroleum gas, 
volatile liquids or sulphur are produced, processed (e.g., compressed), 
stored, transferred (e.g., pumped), or otherwise handled before 
entering the transportation process.
    Projected emissions mean emissions, either controlled or 
uncontrolled, from a source or sources.
    Prospect means a geologic feature having the potential for mineral 
deposits.
    Regional Director means the BOEM officer with responsibility and 
authority for a Region within BOEM.
    Regional Supervisor means the BOEM officer with responsibility and 
authority for operations or other designated program functions within a 
BOEM Region.
    Right-of-use means any authorization issued under this part to use 
OCS lands.
    Right-of-way pipelines are those pipelines that are contained 
within:
    (1) The boundaries of a single lease or unit, but are not owned and 
operated by a lessee or operator of that lease or unit;
    (2) The boundaries of contiguous (not cornering) leases that do not 
have a common lessee or operator;
    (3) The boundaries of contiguous (not cornering) leases that have a 
common lessee or operator but are not owned and operated by that common 
lessee or operator; or
    (4) An unleased block(s).
    Sensitive reservoir means a reservoir in which the production rate 
will affect ultimate recovery.
    Significant archaeological resource means those archaeological 
resources that meet the criteria of significance for eligibility to the 
National Register of Historic Places as defined in 36 CFR 60.4, or its 
successor.
    Suspension means a granted or directed deferral of the requirement 
to produce (Suspension of Production (SOP)) or to conduct leaseholding 
operations (Suspension of Operations (SOO)).
    Venting means the release of gas into the atmosphere without 
igniting it. This includes gas that is released underwater and bubbles 
to the atmosphere.
    Waste of oil, gas, or sulphur means:
    (1) The physical waste of oil, gas, or sulphur;
    (2) The inefficient, excessive, or improper use, or the unnecessary 
dissipation of reservoir energy;
    (3) The locating, spacing, drilling, equipping, operating, or 
producing of any oil, gas, or sulphur well(s) in a manner that causes 
or tends to cause a reduction in the quantity of oil, gas, or sulphur 
ultimately recoverable under prudent and proper operations or that 
causes or tends to cause unnecessary or excessive surface loss or 
destruction of oil or gas; or
    (4) The inefficient storage of oil.
    Welding means all activities connected with welding, including hot 
tapping and burning.
    Wellbay is the area on a facility within the perimeter of the 
outermost wellheads.
    Well-completion operations mean the work conducted to establish 
production from a well after the production-casing string has been set, 
cemented, and pressure-tested.
    Well-control fluid means drilling mud, completion fluid, or 
workover fluid as appropriate to the particular operation being 
conducted.
    Western Gulf of Mexico means all OCS areas of the Gulf of Mexico 
except those the BOEM Director decides are adjacent to the State of 
Florida. The Western Gulf of Mexico is not the same as the Western 
Planning Area, an area established for OCS lease sales.
    Workover operations mean the work conducted on wells after the 
initial well-completion operation for the purpose of maintaining or 
restoring the productivity of a well.
    You means a lessee, the owner or holder of operating rights, a 
designated operator or agent of the lessee(s), a

[[Page 64632]]

pipeline right-of-way holder, or a State lessee granted a right-of-use 
and easement.

Performance Standards

Sec.  550.115  How do I determine well producibility?

    You must follow the procedures in this section to determine well 
producibility if your well is not in the GOM. If your well is in the 
GOM you must follow the procedures in either this section or in Sec.  
550.116 of this subpart.
    (a) You must write to the Regional Supervisor asking for permission 
to determine producibility.
    (b) You must either:
    (1) Allow the Regional Supervisor to witness each test that you 
conduct under this section; or
    (2) Receive the Regional Supervisor prior approval so that you can 
submit either test data with your affidavit or third party test data.
    (c) If the well is an oil well, you must conduct a production test 
that lasts at least 2 hours after flow stabilizes.
    (d) If the well is a gas well, you must conduct a deliverability 
test that lasts at least 2 hours after flow stabilizes, or a four-point 
back pressure test.

Sec.  550.116  How do I determine producibility if my well is in the 
Gulf of Mexico?

    If your well is in the GOM, you must follow either the procedures 
in Sec.  550.115 of this subpart or the procedures in this section to 
determine producibility.
    (a) You must write to the Regional Supervisor asking for permission 
to determine producibility.
    (b) You must provide or make available to the Regional Supervisor, 
as requested, the following log, core, analyses, and test criteria that 
BOEM will consider collectively:
    (1) A log showing sufficient porosity in the producible section.
    (2) Sidewall cores and core analyses that show that the section is 
capable of producing oil or gas.
    (3) Wireline formation test and/or mud-logging analyses that show 
that the section is capable of producing oil or gas.
    (4) A resistivity or induction electric log of the well showing a 
minimum of 15 feet (true vertical thickness except for horizontal 
wells) of producible sand in one section.
    (c) No section that you count as producible under paragraph (b)(4) 
of this section may include any interval that appears to be water 
saturated.
    (d) Each section you count as producible under paragraph (b)(4) of 
this section must exhibit:
    (1) A minimum true resistivity ratio of the producible section to 
the nearest clean or water-bearing sand of at least 5:1; and
    (2) One of the following:
    (i) Electrical spontaneous potential exceeding 20-negative 
millivolts beyond the shale baseline; or
    (ii) Gamma ray log deflection of at least 70 percent of the maximum 
gamma ray deflection in the nearest clean water-bearing sand--if mud 
conditions prevent a 20-negative millivolt reading beyond the shale 
baseline.

Sec.  550.117  How does a determination of well producibility affect 
royalty status?

    A determination of well producibility invokes minimum royalty 
status on the lease as provided in 30 CFR 1202.53.

Sec.  550.118  [Reserved]

Sec.  550.119  Will BOEM approve subsurface gas storage?

    The Regional Supervisor may authorize subsurface storage of gas on 
the OCS, on and off-lease, for later commercial benefit. The Regional 
Supervisor may authorize subsurface storage of gas on the OCS, off-
lease, for later commercial benefit. To receive approval you must:
    (a) Show that the subsurface storage of gas will not result in 
undue interference with operations under existing leases; and
    (b) Sign a storage agreement that includes the required payment of 
a storage fee or rental.

Sec. Sec.  550.120--550.121   [Reserved]

Sec.  550.122  What effect does subsurface storage have on the lease 
term?

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

Sec.  550.123  Will BOEM allow gas storage on unleased lands?

    You may not store gas on unleased lands unless the Regional 
Supervisor approves a right-of-use and easement for that purpose, under 
Sec. Sec.  550.160 through 550.166 of this subpart.

Fees

Sec.  550.125  Service fees.

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

------------------------------------------------------------------------
  Service--processing of the
          following:                 Fee amount         30 CFR citation
------------------------------------------------------------------------
(1) Change in Designation of   $164.................  Sec.   550.143(d).
 Operator.
(2) Right-of-Use and Easement  $2,569...............  Sec.   550.165.
 for State lessee.
(3) [Reserved]...............
(4) Exploration Plan (EP)....  $3,442 for each        Sec.   550.211(d).
                                surface location; no
                                fee for revisions.
(5) Development and            $3,971 for each well   Sec.   550.241(e).
 Production Plan (DPP) or       proposed; no fee for
 Development Operations         revisions.
 Coordination Document (DOCD).
(6) [Reserved]...............
(7) Conservation Information   $25,629..............  Sec.   550.296(a).
 Document.
------------------------------------------------------------------------

     (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.

Sec.  550.126  Electronic payment instructions.

    You must file all payments electronically through Pay.gov. This 
includes, but is not limited to, all OCS applications or filing fee 
payments. The

[[Page 64633]]

Pay.gov Web site may be accessed through a link on the BOEM Offshore 
Web site at: http://www.boem.gov/offshore/ homepage or directly through 
Pay.gov at: https://www.pay.gov/paygov/.
    (a) [Reserved]
    (b) 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.

Inspection of Operations

Sec.  550.130  [Reserved]

Disqualification

Sec.  550.135  What will BOEM do if my operating performance is 
unacceptable?

    If your operating performance is unacceptable, BOEM may disapprove 
or revoke your designation as operator on a single facility or multiple 
facilities. We will give you adequate notice and opportunity for a 
review by BOEM officials before imposing a disqualification.

Sec.  550.136  How will BOEM determine if my performance is 
unacceptable?

    In determining if your operating performance is unacceptable, BOEM 
will consider, individually or collectively:
    (a) [Reserved]
    (b) [Reserved]
    (c) Incidents of noncompliance;
    (d) Civil penalties;
    (e) Failure to adhere to OCS lease obligations; or
    (f) Any other relevant factors.

Special Types of Approvals

Sec.  550.140  When will I receive an oral approval?

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

------------------------------------------------------------------------
    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.
------------------------------------------------------------------------

Sec.  550.141  May I ever use alternate procedures or equipment?

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

Sec.  550.142  How do I receive approval for departures?

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

Sec.  550.143  How do I designate an operator?

    (a) You must provide the Regional Supervisor an executed 
Designation of Operator form (Form BOEM-1123) unless you are the only 
lessee and are the only person conducting lease operations. When there 
is more than one lessee, each lessee must submit the Designation of 
Operator form and the Regional Supervisor must approve the designation 
before the designated operator may begin operations on the leasehold.
    (b) This designation is authority for the designated operator to 
act on your behalf and to fulfill your obligations under the Act, the 
lease, and the regulations in this part.
    (c) You, or your designated operator, must immediately provide the 
Regional Supervisor a written notification of any change of address.
    (d) If you change the designated operator on your lease, you must 
pay the service fee listed in Sec.  550.125 of this subpart with your 
request for a change in designation of operator. Should there be 
multiple lessees, all designation of operator forms must be collected 
by one lessee and submitted to BOEM in a single submittal, which is 
subject to only one filing fee.

Sec.  550.144  How do I designate a new operator when a designation of 
operator terminates?

    (a) When a Designation of Operator terminates, the Regional 
Supervisor must approve a new designated operator before you may 
continue operations. Each lessee must submit a new executed Designation 
of Operator form.
    (b) If your Designation of Operator is terminated, or a controversy 
develops between you and your designated operator, you and your 
designated operator must protect the lessor's interests.

Sec.  550.145  How do I designate an agent or a local agent?

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

Sec.  550.146  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

[[Page 64634]]

which the requirement applies are jointly and severally responsible for 
complying with the regulation.

Right-of-Use and Easement

Sec.  550.160  When will BOEM grant me a right-of-use and easement, and 
what requirements must I meet?

    BOEM may grant you a right-of-use and easement on leased and 
unleased lands on the OCS, if you meet these requirements:
    (a) You must need the right-of-use and easement to construct and 
maintain platforms, artificial islands, and installations and other 
devices at an OCS site other than an OCS lease you own, that are:
    (1) Permanently or temporarily attached to the seabed; and
    (2) Used for conducting exploration, development, and production 
activities or other operations on or off lease; or
    (3) Used for other purposes approved by BOEM.
    (b) You must exercise the right-of-use and easement according to 
the regulations of this part;
    (c) You must meet the requirements at 30 CFR 556.35 (Qualification 
of lessees); establish a regional Company File as required by BOEM; and 
must meet bonding requirements;
    (d) If you apply for a right-of-use and easement on a leased area, 
you must notify the lessee and give her/him an opportunity to comment 
on your application; and
    (e) You must receive BOEM approval for all platforms, artificial 
islands, and installations and other devices permanently or temporarily 
attached to the seabed.
    (f) You must pay a rental amount as required by paragraph (g) of 
this section if:
    (1) You obtain a right-of-use and easement after January 12, 2004; 
or
    (2) You ask BOEM to modify your right-of-use and easement to change 
the footprint of the associated platform, artificial island, or 
installation or device.
    (g) If you meet either of the conditions in paragraph (f) of this 
section, you must pay a rental amount to BOEM as shown in the following 
table:

----------------------------------------------------------------------------------------------------------------
                  If . . .                                                Then . . .
----------------------------------------------------------------------------------------------------------------
(1) Your right-of-use and easement site is    You must pay a rental of $5 per acre per year with a minimum of
 located in water depths of less than 200      $450 per year. The area subject to annual rental includes the
 meters;                                       areal extent of anchor chains, pipeline risers, and other
                                               equipment associated with the platform, artificial island,
                                               installation or device.
(2) Your right-of-use and easement site is    You must pay a rental of $7.50 per acre per year with a minimum of
 located in water depths of 200 meters or      $675 per year. The area subject to annual rental includes the
 greater;                                      areal extent of anchor chains, pipeline risers, and other
                                               equipment associated with the platform, artificial island, or
                                               installation or device.
----------------------------------------------------------------------------------------------------------------

     (h) You may make the rental payments required by paragraph (g)(1) 
and (g)(2) of this section on an annual basis, for a 5-year period, or 
for multiples of 5 years. You must make the first payment 
electronically through Pay.gov and you must include a copy of the 
Pay.gov confirmation receipt page with your right-of-use and easement 
application. You must make all subsequent payments before the 
respective time periods begin.
    (i) Late payments. An interest charge will be assessed on unpaid 
and underpaid amounts from the date the amounts are due, in accordance 
with the provisions found in 30 CFR 1218.54. If you fail to make a 
payment that is late after written notice from BOEM, BOEM may initiate 
cancellation of the right-of-use grant and easement.

Sec.  550.161  What else must I submit with my application?

    With your application, you must describe the proposed use giving:
    (a) Details of the proposed uses and activities including access 
needs and special rights of use that you may need;
    (b) A description of all facilities for which you are seeking 
authorization;
    (c) A map or plat describing primary and alternate project 
locations; and
    (d) A schedule for constructing any new facilities, drilling or 
completing any wells, anticipated production rates, and productive life 
of existing production facilities.

Sec.  550.162  May I continue my right-of-use and easement after the 
termination of any lease on which it is situated?

    If your right-of-use and easement is on a lease, you may continue 
to exercise the right-of-use and easement after the lease on which it 
is situated terminates. You must only use the right-of-use and easement 
for the purpose that the grant specifies. All future lessees of that 
portion of the OCS on which your right-of-use and easement is situated 
must continue to recognize the right-of-use and easement for the 
purpose that the grant specifies.

Sec.  550.163  If I have a State lease, will BOEM grant me a right-of-
use and easement?

    (a) BOEM may grant a lessee of a State lease located adjacent to or 
accessible from the OCS a right-of-use and easement on the OCS.
    (b) BOEM will only grant a right-of-use and easement under this 
paragraph to enable a State lessee to conduct and maintain a device 
that is permanently or temporarily attached to the seabed (i.e., a 
platform, artificial island, or installation). The lessee must use the 
device to explore for, develop, and produce oil and gas from the 
adjacent or accessible State lease and for other operations related to 
these activities.

Sec.  550.164  If I have a State lease, what conditions apply for a 
right-of-use and easement?

    (a) A right-of-use and easement granted under the heading of 
``Right-of-use and easement'' in this subpart is subject to BOEM 
regulations, 30 CFR parts 550 through 582, BSEE regulations, 30 CFR 
parts 250 through 282, and any terms and conditions that the BOEM 
Regional Director or BSEE Regional Director prescribes.
    (b) For the whole or fraction of the first calendar year, and 
annually after that, you must pay to BOEM, in advance, an annual rental 
payment.

Sec.  550.165  If I have a State lease, what fees do I have to pay for 
a right-of-use and easement?

    When you apply for a right-of-use and easement, you must pay:
    (a) A nonrefundable filing fee as specified in Sec.  550.125; and
    (b) The first year's rental as specified in Sec.  550.160(g).

Sec.  550.166  If I have a State lease, what surety bond must I have 
for a right-of-use and easement?

    (a) Before BOEM issues you a right-of-use and easement on the OCS, 
you must furnish the Regional Director a surety bond for $500,000.
    (b) The Regional Director may require additional security from you 
(i.e., security above the prescribed $500,000) to cover additional 
costs and liabilities for regulatory compliance. This additional 
surety:
    (1) Must be in the form of a supplemental bond or bonds meeting the 
requirements of 30 CFR 556.54 (General requirements for bonds) or an

[[Page 64635]]

increase in the coverage of an existing surety bond.
    (2) Covers additional costs and liabilities for regulatory 
compliance, including well abandonment, platform and structure removal, 
and site clearance from the seafloor of the right-of-use and easement.

Primary Lease Requirements, Lease Term Extensions, and Lease 
Cancellations

Sec.  550.181  When may the Secretary cancel my lease and when am I 
compensated for cancellation?

    If the Secretary cancels your lease under this part or under 30 CFR 
part 556, you are entitled to compensation under Sec.  550.184. Section 
550.185 states conditions under which you will receive no compensation. 
The Secretary may cancel a lease after notice and opportunity for a 
hearing when:
    (a) Continued activity on the lease would probably cause harm or 
damage to life (including fish and other aquatic life), property, any 
mineral deposits (in areas leased or not leased), or the marine, 
coastal, or human environment;
    (b) The threat of harm or damage will not disappear or decrease to 
an acceptable extent within a reasonable period of time;
    (c) The advantages of cancellation outweigh the advantages of 
continuing the lease in force; and
    (d) A suspension has been in effect for at least 5 years or you 
request termination of the suspension and lease cancellation.

Sec.  550.182  When may the Secretary cancel a lease at the exploration 
stage?

    BOEM may not approve an exploration plan (EP) under 30 CFR part 
550, subpart B, if the Regional Supervisor determines that the proposed 
activities may cause serious harm or damage to life (including fish and 
other aquatic life), property, any mineral deposits, the National 
security or defense, or to the marine, coastal, or human environment, 
and that the proposed activity cannot be modified to avoid the 
condition(s). The Secretary may cancel the lease if:
    (a) The primary lease term has not expired (or if the lease term 
has been extended) and exploration has been prohibited for 5 years 
following the disapproval; or
    (b) You request cancellation at an earlier time.

Sec.  550.183  When may BOEM or the Secretary extend or cancel a lease 
at the development and production stage?

    (a) BOEM may extend your lease if you submit a DPP and the Regional 
Supervisor disapproves the plan according to the regulations in 30 CFR 
part 550, subpart B. Following the disapproval:
    (1) BOEM will allow you to hold the lease for 5 years, or less time 
at your request;
    (2) Any time within 5 years after the disapproval, you may reapply 
for approval of the same or a modified plan; and
    (3) The Regional Supervisor will approve, disapprove, or require 
modification of the plan under 30 CFR part 550, subpart B.
    (b) If the Regional Supervisor has not approved a DPP or required 
you to submit a DPP for approval or modification, the Secretary will 
cancel the lease:
    (1) When the 5-year period in paragraph (a)(1) of this section 
expires; or
    (2) If you request cancellation at an earlier time.

Sec.  550.184  What is the amount of compensation for lease 
cancellation?

    When the Secretary cancels a lease under Sec. Sec.  550.181, 
550.182 or 550.183 of this subpart, you are entitled to receive 
compensation under 43 U.S.C. 1334(a)(2)(C). You must show the Director 
that the amount of compensation claimed is the lesser of paragraph (a) 
or (b) of this section:
    (a) The fair value of the cancelled rights as of the date of 
cancellation, taking into account both:
    (1) Anticipated revenues from the lease; and
    (2) Costs reasonably anticipated on the lease, including:
    (i) Costs of compliance with all applicable regulations and 
operating orders; and
    (ii) Liability for cleanup costs or damages, or both, in the case 
of an oil spill.
    (b) The excess, if any, over your revenues from the lease (plus 
interest thereon from the date of receipt to date of reimbursement) of:
    (1) All consideration paid for the lease (plus interest from the 
date of payment to the date of reimbursement); and
    (2) All your direct expenditures (plus interest from the date of 
payment to the date of reimbursement):
    (i) After the issue date of the lease; and
    (ii) For exploration or development, or both.
    (c) Compensation for leases issued before September 18, 1978, will 
be equal to the amount specified in paragraph (a) of this section.

Sec.  550.185  When is there no compensation for a lease cancellation?

    You will not receive compensation from BOEM for lease cancellation 
if:
    (a) BOEM disapproves a DPP because you do not receive concurrence 
by the State under section 307(c)(3)(B)(i) or (ii) of the CZMA, and the 
Secretary of Commerce does not make the finding authorized by section 
307(c)(3)(B)(iii) of the CZMA;
    (b) You do not submit a DPP under 30 CFR part 550, subpart B or do 
not comply with the approved DPP;
    (c) As the lessee of a nonproducing lease, you fail to comply with 
the Act, the lease, or the regulations issued under the Act, and the 
default continues for 30 days after BOEM mails you a notice by 
overnight mail;
    (d) The Regional Supervisor disapproves a DPP because you fail to 
comply with the requirements of applicable Federal law; or
    (e) The Secretary forfeits and cancels a producing lease under 
section 5(d) of the Act (43 U.S.C. 1334(d)).

Information and Reporting Requirements

Sec.  550.186  What reporting information and report forms must I 
submit?

    (a) You must submit information and reports as BOEM requires.
    (1) You may obtain copies of forms from, and submit completed forms 
to, the Regional Supervisor.
    (2) Instead of paper copies of forms available from the Regional 
Supervisor, you may use your own computer-generated forms that are 
equal in size to BOEM's forms. You must arrange the data on your form 
identical to the BOEM form. If you generate your own form and it omits 
terms and conditions contained on the official BOEM form, we will 
consider it to contain the omitted terms and conditions.
    (3) You may submit digital data when the Region is equipped to 
accept it.
    (b) When BOEM specifies, you must include, for public information, 
an additional copy of such reports.
    (1) You must mark it Public Information.
    (2) You must include all required information, except information 
exempt from public disclosure under Sec.  550.197 or otherwise exempt 
from public disclosure under law or regulation.

Sec. Sec.  550.187-550.193   [Reserved]

Sec.  550.194  How must I protect archaeological resources?

    (a) If the Regional Director has reason to believe that an 
archaeological resource may exist in the lease area, the Regional 
Director will require in writing

[[Page 64636]]

that your EP, DOCD, or DPP be accompanied by an archaeological report. 
If the archaeological report suggests that an archaeological resource 
may be present, you must either:
    (1) Locate the site of any operation so as not to adversely affect 
the area where the archaeological resource may be; or
    (2) Establish to the satisfaction of the Regional Director that an 
archaeological resource does not exist or will not be adversely 
affected by operations. This requires further archaeological 
investigation, conducted by an archaeologist and a geophysicist, using 
survey equipment and techniques the Regional Director considers 
appropriate. You must submit the investigation report to the Regional 
Director for review.
    (b) If the Regional Director determines that an archaeological 
resource is likely to be present in the lease area and may be adversely 
affected by operations, the Regional Director will notify you 
immediately. You must not take any action that may adversely affect the 
archaeological resource until the Regional Director has told you how to 
protect the resource.
    (c) If you discover any archaeological resource while conducting 
operations in the lease or right-of-way area, you must immediately halt 
operations within the area of the discovery and report the discovery to 
the BOEM Regional Director. If investigations determine that the 
resource is significant, the Regional Director will tell you how to 
protect it.

Sec.  550.195  [Reserved]

Sec.  550.196  Reimbursements for reproduction and processing costs.

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

Sec.  550.197  Data and information to be made available to the public 
or for limited inspection.

    BOEM will protect data and information that you submit under this 
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 BOEM forms will be made 
available to the public upon submission, except as specified in the 
following table:

------------------------------------------------------------------------
                                     Data and
                                 information not   Excepted data will be
         On form . . .             immediately      made available . . .
                                available are . .
                                        .
------------------------------------------------------------------------
(1) [Reserved].                 .................  .....................
(2) [Reserved].                 .................  .....................
(3) [Reserved].                 .................  .....................
(4) [Reserved].                 .................  .....................
(5) [Reserved].                 .................  .....................
(6) BOEM-0127, Sensitive        Items 124 through  2 years after the
 Reservoir Information Report,   168,               effective date of
                                                    the Sensitive
                                                    Reservoir
                                                    Information Report.
(7) [Reserved].                 .................  .....................
(8) [Reserved].                 .................  .....................
(9) BOEM-0137 OCS Plan          Items providing    When the well goes on
 Information,                    the bottomhole     production or
                                 location, true     according to the
                                 vertical depth,    table in paragraph
                                 and measured       (b) of this section,
                                 depth of wells,    whichever is
                                                    earlier.
(10) BOEM-0140, Bottomhole      All items,         2 years after the
 Pressure Survey Report,                            date of the survey.
------------------------------------------------------------------------

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

------------------------------------------------------------------------
                                                             Special
     If . . .      BOEM will release   At this time . .   provisions . .
                         . . .                .                 .
------------------------------------------------------------------------
(1) The Director   Geophysical data,  At any time,       BOEM will
 determines that    Geological data                       release data
 data and           Interpreted G&G                       and
 information are    information,                          information
 needed for         Processed G&G                         only if
 specific           information,                          release would
 scientific or      Analyzed                              further the
 research           geological                            National
 purposes for the   information,                          interest
 Government,                                              without unduly
                                                          damaging the
                                                          competitive
                                                          position of
                                                          the lessee.

[[Page 64637]]

 
(2) Data or        Geophysical data,  60 days after      BOEM will
 information is     Geological data,   BOEM receives      release the
 collected with     Interpreted G&G    the data or        data and
 high-resolution    information,       information, if    information
 systems (e.g.,     Processed          the Regional       earlier than
 bathymetry, side-  geological         Supervisor deems   60 days if the
 scan sonar,        information,       it necessary,      Regional
 subbottom          Analyzed                              Supervisor
 profiler, and      geological                            determines it
 magnetometer) to   information,                          is needed by
 comply with                                              affected
 safety or                                                States to make
 environmental                                            decisions
 protection                                               under subpart
 requirements,                                            B. The
                                                          Regional
                                                          Supervisor
                                                          will
                                                          reconsider
                                                          earlier
                                                          release if you
                                                          satisfy him/
                                                          her that it
                                                          would unduly
                                                          damage your
                                                          competitive
                                                          position.
(3) Your lease is  Geophysical data,  When your lease    This release
 no longer in       Geological data,   terminates,        time applies
 effect,            Processed G&G                         only if the
                    information                           provisions in
                    Interpreted G&G                       this table
                    information,                          governing high-
                    Analyzed                              resolution
                    geological                            systems and
                    information,                          the provisions
                                                          in Sec.
                                                          552.7 do not
                                                          apply. The
                                                          release time
                                                          applies to the
                                                          geophysical
                                                          data and
                                                          information
                                                          only if
                                                          acquired
                                                          postlease for
                                                          a lessee's
                                                          exclusive use.
(4) Your lease is  Geophysical data,  10 years after     This release
 still in effect,   Processed          you submit the     time applies
                    geophysical        data and           only if the
                    information,       information,       provisions in
                    Interpreted G&G                       this table
                    information,                          governing high-
                                                          resolution
                                                          systems and
                                                          the provisions
                                                          in Sec.
                                                          552.7 do not
                                                          apply. This
                                                          release time
                                                          applies to the
                                                          geophysical
                                                          data and
                                                          information
                                                          only if
                                                          acquired
                                                          postlease for
                                                          a lessee's
                                                          exclusive use.
(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 Sec.
                                       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
                                       550.197(b)(5)      according to
                                       and (b)(6),        30 CFR 250
                                       whichever occurs   subpart D.
                                       earlier,
(8) Data and       Any data or        At any time,       None.
 information are    information
 obtained from      obtained,
 beneath unleased
 land as a result
 of a well
 deviation that
 has not been
 approved by the
 Regional
 Supervisor,
(9) Except for     G&G data,          Geological data    None.
 high-resolution    analyzed           and information:
 data and           geological         10 years after
 information        information,       BOEM issues the
 released under     processed and      permit;
 paragraph (b)(2)   interpreted G&G    Geophysical
 of this section    information,       data: 50 years
 data and                              after BOEM
 information                           issues the
 acquired by a                         permit;
 permit under 30                       Geophysical
 CFR part 551 are                      information: 25
 submitted by a                        years after BOEM
 lessee under                          issues the
 part 550, 30 CFR                      permit,
 part 203, or 30
 CFR part 250,
------------------------------------------------------------------------

     (c) BOEM may allow limited inspection, but only by persons with a 
direct interest in related BOEM decisions and issues in specific 
geographic areas, and who agree in writing to its confidentiality, of 
G&G data and information submitted under this part or 30 CFR part 203 
that BOEM uses to:
    (1) [Reserved]
    (2) [Reserved]
    (3) [Reserved]
    (4) Promote operational safety;
    (5) Protect the environment; or
    (6) Make field determinations.
    (7) [Reserved]

References

Sec.  550.198  [Reserved]

Sec.  550.199  Paperwork Reduction Act statements--information 
collection.

    (a) OMB has approved the information collection requirements in 
part 550 under 44 U.S.C. 3501 et seq. The table in paragraph (e) of 
this section

[[Page 64638]]

lists the subpart in the rule requiring the information and its title, 
provides the OMB control number, and summarizes the reasons for 
collecting the information and how BOEM uses the information. The 
associated BOEM forms required by this part are listed at the end of 
this table with the relevant information.
    (b) Respondents are OCS oil, gas, and sulphur lessees and 
operators. The requirement to respond to the information collections in 
this part is mandated under the Act (43 U.S.C. 1331 et seq.) and the 
Act's Amendments of 1978 (43 U.S.C. 1801 et seq.). Some responses are 
also required to obtain or retain a benefit or may be voluntary. 
Proprietary information will be protected under Sec.  550.197, Data and 
information to be made available to the public or for limited 
inspection; parts 551, 552; and the Freedom of Information Act (5 
U.S.C. 552) and its implementing regulations at 43 CFR part 2.
    (c) The Paperwork Reduction Act of 1995 requires us to inform the 
public that an agency may not conduct or sponsor, and you are not 
required to respond to, a collection of information unless it displays 
a currently valid OMB control number.
    (d) Send comments regarding any aspect of the collections of 
information under this part, including suggestions for reducing the 
burden, to the Information Collection Clearance Officer, Bureau of 
Ocean Energy Management, 381 Elden Street, Herndon, VA 20170.
    (e) BOEM is collecting this information for the reasons given in 
the following table:

------------------------------------------------------------------------
 30 CFR subpart, title and/or BOEM Form       Reasons for collecting
           (OMB Control No.)                 information and how used
------------------------------------------------------------------------
(1) Subpart A, General (1010-0114),      To inform BOEM of actions taken
 including Forms BOEM-1123, Designation   to comply with general
 of Operator and BOEM-1832,               requirements on the OCS. To
 Notification of Incidents of             ensure that operations on the
 Noncompliance.                           OCS meet statutory and
                                          regulatory requirements, are
                                          safe and protect the
                                          environment, and result in
                                          diligent exploration,
                                          development, and production on
                                          OCS leases. To support the
                                          unproved and proved reserve
                                          estimation, resource
                                          assessment, and fair market
                                          value determinations.
(2) Subpart B, Exploration and           To inform BOEM, States, and the
 Development and Production Plans (1010-  public of planned exploration,
 0151), including Forms BOEM-0137, OCS    development, and production
 Plan Information Form; BOEM-0138, EP     operations on the OCS. To
 Air Quality Screening Checklist; BOEM-   ensure that operations on the
 0139, DOCD Air Quality Screening         OCS are planned to comply with
 Checklist; BOEM-0141, ROV Survey         statutory and regulatory
 Report Form; and BOEM-0142,              requirements, will be safe and
 Environmental Impact Analysis            protect the human, marine, and
 Worksheet.                               coastal environment, and will
                                          result in diligent
                                          exploration, development, and
                                          production of leases.
(3) Subpart C, Pollution Prevention and  To inform BOEM of measures to
 Control (1010-0057).                     be taken to prevent air
                                          pollution. To ensure that
                                          appropriate measures are taken
                                          to prevent air pollution.
(4) Subpart J, Pipelines and Pipeline    To provide BOEM with
 Rights-of-Way (1010-0050), including     information regarding the
 Form BOEM-2030, Outer Continental        design, installation, and
 Shelf (OCS) Pipeline Right-of-Way        operation of pipelines on the
 Grant Bond.                              OCS. To ensure that pipeline
                                          operations are safe and
                                          protect the human, marine, and
                                          coastal environment.
(5) Subpart K, Oil and Gas Production    To inform BOEM of production
 Rates (1010-0041), including Forms       rates for hydrocarbons
 BOEM-0127, Sensitive Reservoir           produced on the OCS. To ensure
 Information Report and BOEM-0140,        economic maximization of
 Bottomhole Pressure Survey Report.       ultimate hydrocarbon recovery.
(6) Subpart N, Remedies and Penalties..  The requirements in subpart N
                                          are exempt from the Paperwork
                                          Reduction Act of 1995
                                          according to 5 CFR 1320.4.
------------------------------------------------------------------------

Subpart B--Plans and Information

General Information

Sec.  550.200  Definitions.

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

[[Page 64639]]

Sec.  550.201  What plans and information must I submit before I 
conduct any activities on my lease or unit?

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

------------------------------------------------------------------------
  You must submit a(n) . . .                Before you . . .
------------------------------------------------------------------------
(1) Exploration Plan (EP),     Conduct any exploration activities on a
                                lease or unit.
(2) Development and            Conduct any development and production
 Production Plan (DPP),         activities on a lease or unit in any OCS
                                area other than the Western Gulf of
                                Mexico.
(3) Development Operations     Conduct any development and production
 Coordination Document          activities on a lease or unit in the
 (DOCD),                        Western GOM.
(4) BSEE approved Deepwater    Conduct post-drilling installation
 Operations Plan (DWOP),        activities in any water depth associated
                                with a development project that will
                                involve the use of a non-conventional
                                production or completion technology.
(5) Conservation Information   Commence production from development
 Document (CID),                projects in water depths greater than
                                1,312 feet (400 meters).
(6) EP, DPP, or DOCD,          Conduct geological or geophysical (G&G)
                                exploration or a development G&G
                                activity (see definitions under Sec.
                                550.105) on your lease or unit when:
                               (i) It will result in a physical
                                penetration of the seabed greater than
                                500 feet (152 meters);
                               (ii) It will involve the use of
                                explosives;
                               (iii) The Regional Director determines
                                that it might have a significant adverse
                                effect on the human, marine, or coastal
                                environment; or
                               (iv) The Regional Supervisor, after
                                reviewing a notice under Sec.   550.209,
                                determines that an EP, DPP, or DOCD is
                                necessary.
------------------------------------------------------------------------

     (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 BOEM;
    (2) Other coastal or marine resources are not present or affected;
    (3) Other factors such as technological advances affect information 
needs; or
    (4) Information is not necessary or required for a State to 
determine consistency with their CZMA Plan.
    (d) Referencing. In preparing your proposed plan or document, you 
may reference information and data discussed in other plans or 
documents you previously submitted or that are otherwise readily 
available to BOEM.

Sec.  550.202  What criteria must the Exploration Plan (EP), 
Development and Production Plan (DPP), or Development Operations 
Coordination Document (DOCD) meet?

    Your EP, DPP, or DOCD must demonstrate that you have planned and 
are prepared to conduct the proposed activities in a manner that:
    (a) Conforms to the Outer Continental Shelf Lands Act as amended 
(Act), applicable implementing regulations, lease provisions and 
stipulations, and other Federal laws;
    (b) Is safe;
    (c) Conforms to sound conservation practices and protects the 
rights of the lessor;
    (d) Does not unreasonably interfere with other uses of the OCS, 
including those involved with National security or defense; and
    (e) Does not cause undue or serious harm or damage to the human, 
marine, or coastal environment.

Sec.  550.203  Where can wells be located under an EP, DPP, or DOCD?

    The Regional Supervisor reviews and approves proposed well location 
and spacing under an EP, DPP, or DOCD. In deciding whether to approve a 
proposed well location and spacing, the Regional Supervisor will 
consider factors including, but not limited to, the following:
    (a) Protecting correlative rights;
    (b) Protecting Federal royalty interests;
    (c) Recovering optimum resources;
    (d) Number of wells that can be economically drilled for proper 
reservoir management;
    (e) Location of drilling units and platforms;
    (f) Extent and thickness of the reservoir;
    (g) Geologic and other reservoir characteristics;
    (h) Minimizing environmental risk;
    (i) Preventing unreasonable interference with other uses of the 
OCS; and
    (j) Drilling of unnecessary wells.

Sec. Sec.  550.204  550.205 [Reserved]

Sec.  550.206  How do I submit the EP, DPP, or DOCD?

    (a) Number of copies. When you submit an EP, DPP, or DOCD to BOEM, 
you must provide:
    (1) Four copies that contain all required information (proprietary 
copies);
    (2) Eight copies for public distribution (public information 
copies) that omit information that you assert is exempt from disclosure 
under the Freedom of Information Act (FOIA) (5 U.S.C. 552) and the 
implementing regulations (43 CFR part 2); and
    (3) Any additional copies that may be necessary to facilitate 
review of the EP, DPP, or DOCD by certain affected States and other 
reviewing entities.
    (b) Electronic submission. You may submit part or all of your EP, 
DPP, or DOCD and its accompanying information electronically. If you 
prefer to submit your EP, DPP, or DOCD electronically, ask the Regional 
Supervisor for further guidance.
    (c) Withdrawal after submission. You may withdraw your proposed EP, 
DPP, or DOCD at any time for any reason. Notify the appropriate BOEM 
OCS Region if you do.

Ancillary Activities

Sec.  550.207  What ancillary activities may I conduct?

    Before or after you submit an EP, DPP, or DOCD to BOEM, you may 
elect, the regulations in this part may require, or the Regional 
Supervisor may direct you to conduct ancillary activities. Ancillary 
activities include:

[[Page 64640]]

    (a) Geological and geophysical (G&G) explorations and development 
G&G activities;
    (b) Geological and high-resolution geophysical, geotechnical, 
archaeological, biological, physical oceanographic, meteorological, 
socioeconomic, or other surveys; or
    (c) Studies that model potential oil and hazardous substance 
spills, drilling muds and cuttings discharges, projected air emissions, 
or potential hydrogen sulfide (H2S) releases.

Sec.  550.208  If I conduct ancillary activities, what notices must I 
provide?

    At least 30 calendar days before you conduct any G&G exploration or 
development G&G activity (see Sec.  550.207(a)), you must notify the 
Regional Supervisor in writing.
    (a) When you prepare the notice, you must:
    (1) Sign and date the notice;
    (2) Provide the names of the vessel, its operator, and the 
person(s) in charge; the specific type(s) of operations you will 
conduct; and the instrumentation/techniques and vessel navigation 
system you will use;
    (3) Provide expected start and completion dates and the location of 
the activity; and
    (4) Describe the potential adverse environmental effects of the 
proposed activity and any mitigation to eliminate or minimize these 
effects on the marine, coastal, and human environment.
    (b) The Regional Supervisor may require you to:
    (1) Give written notice to BOEM at least 15 calendar days before 
you conduct any other ancillary activity (see Sec.  550.207(b) and (c)) 
in addition to those listed in Sec.  550.207(a); and
    (2) Notify other users of the OCS before you conduct any ancillary 
activity.

Sec.  550.209  What is the BOEM review process for the notice?

    The Regional Supervisor will review any notice required under Sec.  
550.208(a) and (b)(1) to ensure that your ancillary activity complies 
with the performance standards listed in Sec.  550.202(a), (b), (d), 
and (e). The Regional Supervisor may notify you that your ancillary 
activity does not comply with those standards. In such a case, the 
Regional Supervisor will require you to submit an EP, DPP, or DOCD and 
you may not start your ancillary activity until the Regional Supervisor 
approves the EP, DPP, or DOCD.

Sec.  550.210  If I conduct ancillary activities, what reporting and 
data/information retention requirements must I satisfy?

    (a) Reporting. The Regional Supervisor may require you to prepare 
and submit reports that summarize and analyze data or information 
obtained or derived from your ancillary activities. When applicable, 
BOEM will protect and disclose the data and information in these 
reports in accordance with Sec.  550.197(b).
    (b) Data and information retention. You must retain copies of all 
original data and information, including navigation data, obtained or 
derived from your G&G explorations and development G&G activities (see 
Sec.  550.207(a)), including any such data and information you obtained 
from previous leaseholders or unit operators. You must submit such data 
and information to BOEM for inspection and possible retention upon 
request at any time before lease or unit termination. When applicable, 
BOEM will protect and disclose such submitted data and information in 
accordance with Sec.  550.197(b).

Contents of Exploration Plans (EP)

Sec.  550.211  What must the EP include?

    Your EP must include the following:
    (a) Description, objectives, and schedule. A description, 
discussion of the objectives, and tentative schedule (from start to 
completion) of the exploration activities that you propose to 
undertake. Examples of exploration activities include exploration 
drilling, well test flaring, installing a well protection structure, 
and temporary well abandonment.
    (b) Location. A map showing the surface location and water depth of 
each proposed well and the locations of all associated drilling unit 
anchors.
    (c) Drilling unit. A description of the drilling unit and 
associated equipment you will use to conduct your proposed exploration 
activities, including a brief description of its important safety and 
pollution prevention features, and a table indicating the type and the 
estimated maximum quantity of fuels, oil, and lubricants that will be 
stored on the facility (see definition of ``facility'' under Sec.  
550.105(3)).
    (d) Service fee. You must include payment of the service fee listed 
in Sec.  550.125.

Sec.  550.212  What information must accompany the EP?

    The following information must accompany your EP:
    (a) General information required by Sec.  550.213;
    (b) Geological and geophysical (G&G) information required by Sec.  
550.214;
    (c) Hydrogen sulfide information required by Sec.  550.215;
    (d) Biological, physical, and socioeconomic information required by 
Sec.  550.216;
    (e) Solid and liquid wastes and discharges information and cooling 
water intake information required by Sec.  550.217;
    (f) Air emissions information required by Sec.  550.218;
    (g) Oil and hazardous substance spills information required by 
Sec.  550.219;
    (h) Alaska planning information required by Sec.  550.220;
    (i) Environmental monitoring information required by Sec.  550.221;
    (j) Lease stipulations information required by Sec.  550.222;
    (k) Mitigation measures information required by Sec.  550.223;
    (l) Support vessels and aircraft information required by Sec.  
550.224;
    (m) Onshore support facilities information required by Sec.  
550.225;
    (n) Coastal zone management information required by Sec.  550.226;
    (o) Environmental impact analysis information required by Sec.  
550.227; and
    (p) Administrative information required by Sec.  550.228.

Sec.  550.213  What general information must accompany the EP?

    The following general information must accompany your EP:
    (a) Applications and permits. A listing, including filing or 
approval status, of the Federal, State, and local application approvals 
or permits you must obtain to conduct your proposed exploration 
activities.
    (b) Drilling fluids. A table showing the projected amount, 
discharge rate, and chemical constituents for each type (i.e., water-
based, oil-based, synthetic-based) of drilling fluid you plan to use to 
drill your proposed exploration wells.
    (c) Chemical products. A table showing the name and brief 
description, quantities to be stored, storage method, and rates of 
usage of the chemical products you will use to conduct your proposed 
exploration activities. List only those chemical products you will 
store or use in quantities greater than the amounts defined as 
Reportable Quantities in 40 CFR part 302, or amounts specified by the 
Regional Supervisor.
    (d) New or unusual technology. A description and discussion of any 
new or unusual technology (see definition under Sec.  550.200) you will 
use to carry out your proposed exploration activities. In the public 
information copies of your EP, you may exclude any

[[Page 64641]]

proprietary information from this description. In that case, include a 
brief discussion of the general subject matter of the omitted 
information. If you will not use any new or unusual technology to carry 
out your proposed exploration activities, include a statement so 
indicating.
    (e) Bonds, oil spill financial responsibility, and well control 
statements. Statements attesting that:
    (1) The activities and facilities proposed in your EP are or will 
be covered by an appropriate bond under 30 CFR part 556, subpart I;
    (2) You have demonstrated or will demonstrate oil spill financial 
responsibility for facilities proposed in your EP according to 30 CFR 
part 553; and
    (3) You have or will have the financial capability to drill a 
relief well and conduct other emergency well control operations.
    (f) Suspensions of operations. A brief discussion of any 
suspensions of operations that you anticipate may be necessary in the 
course of conducting your activities under the EP.
    (g) Blowout scenario. A scenario for the potential blowout of the 
proposed well in your EP that you expect will have the highest volume 
of liquid hydrocarbons. Include the estimated flow rate, total volume, 
and maximum duration of the potential blowout. Also, discuss the 
potential for the well to bridge over, the likelihood for surface 
intervention to stop the blowout, the availability of a rig to drill a 
relief well, and rig package constraints. Estimate the time it would 
take to drill a relief well.
    (h) Contact. The name, address (e-mail address, if available), and 
telephone number of the person with whom the Regional Supervisor and 
any affected State(s) can communicate about your EP.

Sec.  550.214  What geological and geophysical (G&G) information must 
accompany the EP?

    The following G&G information must accompany your EP:
    (a) Geological description. A geological description of the 
prospect(s).
    (b) Structure contour maps. Current structure contour maps (depth-
based, expressed in feet subsea) drawn on the top of each prospective 
hydrocarbon-bearing reservoir showing the locations of proposed wells.
    (c) Two-dimensional (2-D) or three-dimensional (3-D) seismic lines. 
Copies of migrated and annotated 2-D or 3-D seismic lines (with depth 
scale) intersecting at or near your proposed well locations. You are 
not required to conduct both 2-D and 3-D seismic surveys if you choose 
to conduct only one type of survey. If you have conducted both types of 
surveys, the Regional Supervisor may instruct you to submit the results 
of both surveys. You must interpret and display this information. 
Because of its volume, provide this information as an enclosure to only 
one proprietary copy of your EP.
    (d) Geological cross-sections. Interpreted geological cross-
sections showing the location and depth of each proposed well.
    (e) Shallow hazards report. A shallow hazards report based on 
information obtained from a high-resolution geophysical survey, or a 
reference to such report if you have already submitted it to the 
Regional Supervisor.
    (f) Shallow hazards assessment. For each proposed well, an 
assessment of any seafloor and subsurface geological and manmade 
features and conditions that may adversely affect your proposed 
drilling operations.
    (g) High-resolution seismic lines. A copy of the high-resolution 
survey line closest to each of your proposed well locations. Because of 
its volume, provide this information as an enclosure to only one 
proprietary copy of your EP. You are not required to provide this 
information if the surface location of your proposed well has been 
approved in a previously submitted EP, DPP, or DOCD.
    (h) Stratigraphic column. A generalized biostratigraphic/
lithostratigraphic column from the surface to the total depth of the 
prospect.
    (i) Time-versus-depth chart. A seismic travel time-versus-depth 
chart based on the appropriate velocity analysis in the area of 
interpretation and specifying the geodetic datum.
    (j) Geochemical information. A copy of any geochemical reports you 
used or generated.
    (k) Future G&G activities. A brief description of the types of G&G 
explorations and development G&G activities you may conduct for lease 
or unit purposes after your EP is approved.

Sec.  550.215  What hydrogen sulfide (H2S) information must 
accompany the EP?

    The following H2S information, as applicable, must 
accompany your EP:
    (a) Concentration. The estimated concentration of any 
H2S you might encounter while you conduct your proposed 
exploration activities.
    (b) Classification. Under 30 CFR 250.490(c), a request that the 
BSEE Regional Supervisor classify the area of your proposed exploration 
activities as either H2S absent, H2S present, or 
H2S unknown. Provide sufficient information to justify your 
request.
    (c) H2S Contingency Plan. If you ask the Regional 
Supervisor to classify the area of your proposed exploration activities 
as either H2S present or H2S unknown, an 
H2S Contingency Plan prepared under 30 CFR 250.490(f), or a 
reference to an approved or submitted H2S Contingency Plan 
that covers the proposed exploration activities.
    (d) Modeling report. If you modeled a potential H2S 
release when developing your EP, modeling report or the modeling 
results, or a reference to such report or results if you have already 
submitted it to the Regional Supervisor.
    (1) The analysis in the modeling report must be specific to the 
particular site of your proposed exploration activities, and must 
consider any nearby human-occupied OCS facilities, shipping lanes, 
fishery areas, and other points where humans may be subject to 
potential exposure from an H2S release from your proposed 
exploration activities.
    (2) If any H2S emissions are projected to affect an 
onshore location in concentrations greater than 10 parts per million, 
the modeling analysis must be consistent with the Environmental 
Protection Agency's (EPA) risk management plan methodologies outlined 
in 40 CFR part 68.

Sec.  550.216  What biological, physical, and socioeconomic information 
must accompany the EP?

    If you obtain the following information in developing your EP, or 
if the Regional Supervisor requires you to obtain it, you must include 
a report, or the information obtained, or a reference to such a report 
or information if you have already submitted it to the Regional 
Supervisor, as accompanying information:
    (a) Biological environment reports. Site-specific information on 
chemosynthetic communities, federally listed threatened or endangered 
species, marine mammals protected under the Marine Mammal Protection 
Act (MMPA), sensitive underwater features, marine sanctuaries, critical 
habitat designated under the Endangered Species Act (ESA), or other 
areas of biological concern.
    (b) Physical environment reports. Site-specific meteorological, 
physical oceanographic, geotechnical reports, or archaeological reports 
(if required under Sec.  550.194).
    (c) Socioeconomic study reports. Socioeconomic information 
regarding your proposed exploration activities.

[[Page 64642]]

Sec.  550.217  What solid and liquid wastes and discharges information 
and cooling water intake information must accompany the EP?

    The following solid and liquid wastes and discharges information 
and cooling water intake information must accompany your EP:
    (a) Projected wastes. A table providing the name, brief 
description, projected quantity, and composition of solid and liquid 
wastes (such as spent drilling fluids, drill cuttings, trash, sanitary 
and domestic wastes, and chemical product wastes) likely to be 
generated by your proposed exploration activities. Describe:
    (1) The methods you used for determining this information; and
    (2) Your plans for treating, storing, and downhole disposal of 
these wastes at your drilling location(s).
    (b) Projected ocean discharges. If any of your solid and liquid 
wastes will be discharged overboard, or are planned discharges from 
manmade islands:
    (1) A table showing the name, projected amount, and rate of 
discharge for each waste type; and
    (2) A description of the discharge method (such as shunting through 
a downpipe, etc.) you will use.
    (c) National Pollutant Discharge Elimination System (NPDES) permit. 
(1) A discussion of how you will comply with the provisions of the 
applicable general NPDES permit that covers your proposed exploration 
activities; or
    (2) A copy of your application for an individual NPDES permit. 
Briefly describe the major discharges and methods you will use for 
compliance.
    (d) Modeling report. The modeling report or the modeling results 
(if you modeled the discharges of your projected solid or liquid wastes 
when developing your EP), or a reference to such report or results if 
you have already submitted it to the Regional Supervisor.
    (e) Projected cooling water intake. A table for each cooling water 
intake structure likely to be used by your proposed exploration 
activities that includes a brief description of the cooling water 
intake structure, daily water intake rate, water intake through screen 
velocity, percentage of water intake used for cooling water, mitigation 
measures for reducing impingement and entrainment of aquatic organisms, 
and biofouling prevention measures.

Sec.  550.218  What air emissions information must accompany the EP?

    The following air emissions information, as applicable, must 
accompany your EP:
    (a) Projected emissions. Tables showing the projected emissions of 
sulphur dioxide (SO2), particulate matter in the form of 
PM10 and PM2.5 when applicable, nitrogen oxides 
(NOX), carbon monoxide (CO), and volatile organic compounds 
(VOC) that will be generated by your proposed exploration activities.
    (1) For each source on or associated with the drilling unit 
(including well test flaring and well protection structure 
installation), you must list:
    (i) The projected peak hourly emissions;
    (ii) The total annual emissions in tons per year;
    (iii) Emissions over the duration of the proposed exploration 
activities;
    (iv) The frequency and duration of emissions; and
    (v) The total of all emissions listed in paragraphs (a)(1)(i) 
through (iv) of this section.
    (2) You must provide the basis for all calculations, including 
engine size and rating, and applicable operational information.
    (3) You must base the projected emissions on the maximum rated 
capacity of the equipment on the proposed drilling unit under its 
physical and operational design.
    (4) If the specific drilling unit has not yet been determined, you 
must use the maximum emission estimates for the type of drilling unit 
you will use.
    (b) Emission reduction measures. A description of any proposed 
emission reduction measures, including the affected source(s), the 
emission reduction control technologies or procedures, the quantity of 
reductions to be achieved, and any monitoring system you propose to use 
to measure emissions.
    (c) Processes, equipment, fuels, and combustibles. A description of 
processes, processing equipment, combustion equipment, fuels, and 
storage units. You must include the characteristics and the frequency, 
duration, and maximum burn rate of any well test fluids to be burned.
    (d) Distance to shore. Identification of the distance of your 
drilling unit from the mean high water mark (mean higher high water 
mark on the Pacific coast) of the adjacent State.
    (e) Non-exempt drilling units. A description of how you will comply 
with Sec.  550.303 when the projected emissions of SO2, PM, 
NOX, CO, or VOC, that will be generated by your proposed 
exploration activities, are greater than the respective emission 
exemption amounts ``E'' calculated using the formulas in Sec.  
550.303(d). When BOEM requires air quality modeling, you must use the 
guidelines in Appendix W of 40 CFR part 51 with a model approved by the 
Director. Submit the best available meteorological information and data 
consistent with the model(s) used.
    (f) Modeling report. A modeling report or the modeling results (if 
Sec.  550.303 requires you to use an approved air quality model to 
model projected air emissions in developing your EP), or a reference to 
such a report or results if you have already submitted it to the 
Regional Supervisor.

Sec.  550.219  What oil and hazardous substance spills information must 
accompany the EP?

    The following information regarding potential spills of oil (see 
definition under 30 CFR 254.6) and hazardous substances (see definition 
under 40 CFR part 116) as applicable, must accompany your EP:
    (a) Oil spill response planning. The material required under 
paragraph (a)(1) or (a)(2) of this section:
    (1) An Oil Spill Response Plan (OSRP) for the facilities you will 
use to conduct your exploration activities prepared according to the 
requirements of 30 CFR part 254, subpart B; or
    (2) Reference to your approved regional OSRP (see 30 CFR 254.3) to 
include:
    (i) A discussion of your regional OSRP;
    (ii) The location of your primary oil spill equipment base and 
staging area;
    (iii) The name(s) of your oil spill removal organization(s) for 
both equipment and personnel;
    (iv) The calculated volume of your worst case discharge scenario 
(see 30 CFR 254.26(a)), and a comparison of the appropriate worst case 
discharge scenario in your approved regional OSRP with the worst case 
discharge scenario that could result from your proposed exploration 
activities; and
    (v) A description of the worst case discharge scenario that could 
result from your proposed exploration activities (see 30 CFR 254.26(b), 
(c), (d), and (e)).
    (b) Modeling report. If you model a potential oil or hazardous 
substance spill in developing your EP, a modeling report or the 
modeling results, or a reference to such report or results if you have 
already submitted it to the Regional Supervisor.

Sec.  550.220  If I propose activities in the Alaska OCS Region, what 
planning information must accompany the EP?

    If you propose exploration activities in the Alaska OCS Region, the 
following planning information must accompany your EP:
    (a) Emergency plans. A description of your emergency plans to 
respond to a

[[Page 64643]]

blowout, loss or disablement of a drilling unit, and loss of or damage 
to support craft.
    (b) Critical operations and curtailment procedures. Critical 
operations and curtailment procedures for your exploration activities. 
The procedures must identify ice conditions, weather, and other 
constraints under which the exploration activities will either be 
curtailed or not proceed.

Sec.  550.221  What environmental monitoring information must accompany 
the EP?

    The following environmental monitoring information, as applicable, 
must accompany your EP:
    (a) Monitoring systems. A description of any existing and planned 
monitoring systems that are measuring, or will measure, environmental 
conditions or will provide project-specific data or information on the 
impacts of your exploration activities.
    (b) Incidental takes. If there is reason to believe that protected 
species may be incidentally taken by planned exploration activities, 
you must describe how you will monitor for incidental take of:
    (1) Threatened and endangered species listed under the ESA; and
    (2) Marine mammals, as appropriate, if you have not already 
received authorization for incidental take as may be necessary under 
the MMPA.
    (c) Flower Garden Banks National Marine Sanctuary (FGBNMS). If you 
propose to conduct exploration activities within the protective zones 
of the FGBNMS, a description of your provisions for monitoring the 
impacts of an oil spill on the environmentally sensitive resources at 
the FGBNMS.

Sec.  550.222  What lease stipulations information must accompany the 
EP?

    A description of the measures you took, or will take, to satisfy 
the conditions of lease stipulations related to your proposed 
exploration activities must accompany your EP.

Sec.  550.223  What mitigation measures information must accompany the 
EP?

    (a) If you propose to use any measures beyond those required by the 
regulations in this part to minimize or mitigate environmental impacts 
from your proposed exploration activities, a description of the 
measures you will use must accompany your EP.
    (b) If there is reason to believe that protected species may be 
incidentally taken by planned exploration activities, you must include 
mitigation measures designed to avoid or minimize the incidental take 
of:
    (1) Threatened and endangered species listed under the ESA; and
    (2) Marine mammals, as appropriate, if you have not already 
received authorization for incidental take as may be necessary under 
the MMPA.

Sec.  550.224  What information on support vessels, offshore vehicles, 
and aircraft you will use must accompany the EP?

    The following information on the support vessels, offshore 
vehicles, and aircraft you will use must accompany your EP:
    (a) General. A description of the crew boats, supply boats, anchor 
handling vessels, tug boats, barges, ice management vessels, other 
vessels, offshore vehicles, and aircraft you will use to support your 
exploration activities. The description of vessels and offshore 
vehicles must estimate the storage capacity of their fuel tanks and the 
frequency of their visits to your drilling unit.
    (b) Air emissions. A table showing the source, composition, 
frequency, and duration of the air emissions likely to be generated by 
the support vessels, offshore vehicles, and aircraft you will use that 
will operate within 25 miles of your drilling unit.
    (c) Drilling fluids and chemical products transportation. A 
description of the transportation method and quantities of drilling 
fluids and chemical products (see Sec.  550.213(b) and (c)) you will 
transport from the onshore support facilities you will use to your 
drilling unit.
    (d) Solid and liquid wastes transportation. A description of the 
transportation method and a brief description of the composition, 
quantities, and destination(s) of solid and liquid wastes (see Sec.  
550.217(a)) you will transport from your drilling unit.
    (e) Vicinity map. A map showing the location of your proposed 
exploration activities relative to the shoreline. The map must depict 
the primary route(s) the support vessels and aircraft will use when 
traveling between the onshore support facilities you will use and your 
drilling unit.

Sec.  550.225  What information on the onshore support facilities you 
will use must accompany the EP?

    The following information on the onshore support facilities you 
will use must accompany your EP:
    (a) General. A description of the onshore facilities you will use 
to provide supply and service support for your proposed exploration 
activities (e.g., service bases and mud company docks).
    (1) Indicate whether the onshore support facilities are existing, 
to be constructed, or to be expanded.
    (2) If the onshore support facilities are, or will be, located in 
areas not adjacent to the Western GOM, provide a timetable for 
acquiring lands (including rights-of-way and easements) and 
constructing or expanding the facilities. Describe any State or Federal 
permits or approvals (dredging, filling, etc.) that would be required 
for constructing or expanding them.
    (b) Air emissions. A description of the source, composition, 
frequency, and duration of the air emissions (attributable to your 
proposed exploration activities) likely to be generated by the onshore 
support facilities you will use.
    (c) Unusual solid and liquid wastes. A description of the quantity, 
composition, and method of disposal of any unusual solid and liquid 
wastes (attributable to your proposed exploration activities) likely to 
be generated by the onshore support facilities you will use. Unusual 
wastes are those wastes not specifically addressed in the relevant 
National Pollution Discharge Elimination System (NPDES) permit.
    (d) Waste disposal. A description of the onshore facilities you 
will use to store and dispose of solid and liquid wastes generated by 
your proposed exploration activities (see Sec.  550.217) and the types 
and quantities of such wastes.

Sec.  550.226  What Coastal Zone Management Act (CZMA) information must 
accompany the EP?

    The following CZMA information must accompany your EP:
    (a) Consistency certification. A copy of your consistency 
certification under section 307(c)(3)(B) of the CZMA (16 U.S.C. 
1456(c)(3)(B)) and 15 CFR 930.76(d) stating that the proposed 
exploration activities described in detail in this EP comply with (name 
of State(s)) approved coastal management program(s) and will be 
conducted in a manner that is consistent with such program(s); and
    (b) Other information. ``Information'' as required by 15 CFR 
930.76(a) and 15 CFR 930.58(a)(2)) and ``Analysis'' as required by 15 
CFR 930.58(a)(3).

Sec.  550.227  What environmental impact analysis (EIA) information 
must accompany the EP?

    The following EIA information must accompany your EP:
    (a) General requirements. Your EIA must:
    (1) Assess the potential environmental impacts of your proposed 
exploration activities;
    (2) Be project specific; and

[[Page 64644]]

    (3) Be as detailed as necessary to assist the Regional Supervisor 
in complying with the National Environmental Policy Act (NEPA) of 1969 
(42 U.S.C. 4321 et seq.) and other relevant Federal laws such as the 
ESA and the MMPA.
    (b) Resources, conditions, and activities. Your EIA must describe 
those resources, conditions, and activities listed below that could be 
affected by your proposed exploration activities, or that could affect 
the construction and operation of facilities or structures, or the 
activities proposed in your EP.
    (1) Meteorology, oceanography, geology, and shallow geological or 
manmade hazards;
    (2) Air and water quality;
    (3) Benthic communities, marine mammals, sea turtles, coastal and 
marine birds, fish and shellfish, and plant life;
    (4) Threatened or endangered species and their critical habitat as 
defined by the Endangered Species Act of 1973;
    (5) Sensitive biological resources or habitats such as essential 
fish habitat, refuges, preserves, special management areas identified 
in coastal management programs, sanctuaries, rookeries, and calving 
grounds;
    (6) Archaeological resources;
    (7) Socioeconomic resources including employment, existing offshore 
and coastal infrastructure (including major sources of supplies, 
services, energy, and water), land use, subsistence resources and 
harvest practices, recreation, recreational and commercial fishing 
(including typical fishing seasons, location, and type), minority and 
lower income groups, and coastal zone management programs;
    (8) Coastal and marine uses such as military activities, shipping, 
and mineral exploration or development; and
    (9) Other resources, conditions, and activities identified by the 
Regional Supervisor.
    (c) Environmental impacts. Your EIA must:
    (1) Analyze the potential direct and indirect impacts (including 
those from accidents, cooling water intake structures, and those 
identified in relevant ESA biological opinions such as, but not limited 
to, those from noise, vessel collisions, and marine trash and debris) 
that your proposed exploration activities will have on the identified 
resources, conditions, and activities;
    (2) Analyze any potential cumulative impacts from other activities 
to those identified resources, conditions, and activities potentially 
impacted by your proposed exploration activities;
    (3) Describe the type, severity, and duration of these potential 
impacts and their biological, physical, and other consequences and 
implications;
    (4) Describe potential measures to minimize or mitigate these 
potential impacts; and
    (5) Summarize the information you incorporate by reference.
    (d) Consultation. Your EIA must include a list of agencies and 
persons with whom you consulted, or with whom you will be consulting, 
regarding potential impacts associated with your proposed exploration 
activities.
    (e) References cited. Your EIA must include a list of the 
references that you cite in the EIA.

Sec.  550.228  What administrative information must accompany the EP?

    The following administrative information must accompany your EP:
    (a) Exempted information description (public information copies 
only). A description of the general subject matter of the proprietary 
information that is included in the proprietary copies of your EP or 
its accompanying information.
    (b) Bibliography. (1) If you reference a previously submitted EP, 
DPP, DOCD, study report, survey report, or other material in your EP or 
its accompanying information, a list of the referenced material; and
    (2) The location(s) where the Regional Supervisor can inspect the 
cited referenced material if you have not submitted it.

Review and Decision Process for the EP

Sec.  550.231  After receiving the EP, what will BOEM do?

    (a) Determine whether deemed submitted. Within 15 working days 
after receiving your proposed EP and its accompanying information, the 
Regional Supervisor will review your submission and deem your EP 
submitted if:
    (1) The submitted information, including the information that must 
accompany the EP (refer to the list in Sec.  550.212), fulfills 
requirements and is sufficiently accurate;
    (2) You have provided all needed additional information (see Sec.  
550.201(b)); and
    (3) You have provided the required number of copies (see Sec.  
550.206(a)).
    (b) Identify problems and deficiencies. If the Regional Supervisor 
determines that you have not met one or more of the conditions in 
paragraph (a) of this section, the Regional Supervisor will notify you 
of the problem or deficiency within 15 working days after the Regional 
Supervisor receives your EP and its accompanying information. The 
Regional Supervisor will not deem your EP submitted until you have 
corrected all problems or deficiencies identified in the notice.
    (c) Deemed submitted notification. The Regional Supervisor will 
notify you when the EP is deemed submitted.

Sec.  550.232  What actions will BOEM take after the EP is deemed 
submitted?

    (a) State and CZMA consistency reviews. Within 2 working days after 
deeming your EP submitted under Sec.  550.231, the Regional Supervisor 
will use receipted mail or alternative method to send a public 
information copy of the EP and its accompanying information to the 
following:
    (1) The Governor of each affected State. The Governor has 21 
calendar days after receiving your deemed-submitted EP to submit 
comments. The Regional Supervisor will not consider comments received 
after the deadline.
    (2) The CZMA agency of each affected State. The CZMA consistency 
review period under section 307(c)(3)(B)(ii) of the CZMA (16 U.S.C. 
1456(c)(3)(B)(ii)) and 15 CFR 930.78 begins when the State's CZMA 
agency receives a copy of your deemed-submitted EP, consistency 
certification, and required necessary data and information (see 15 CFR 
930.77(a)(1)).
    (b) BOEM compliance review. The Regional Supervisor will review the 
exploration activities described in your proposed EP to ensure that 
they conform to the performance standards in Sec.  550.202.
    (c) BOEM environmental impact evaluation. The Regional Supervisor 
will evaluate the environmental impacts of the activities described in 
your proposed EP and prepare environmental documentation under the 
National Environmental Policy Act (NEPA) (42 U.S.C. 4321 et seq.) and 
the implementing regulations (40 CFR parts 1500 through 1508).
    (d) Amendments. During the review of your proposed EP, the Regional 
Supervisor may require you, or you may elect, to change your EP. If you 
elect to amend your EP, the Regional Supervisor may determine that your 
EP, as amended, is subject to the requirements of Sec.  550.231.

Sec.  550.233  What decisions will BOEM make on the EP and within what 
timeframe?

    (a) Timeframe. The Regional Supervisor will take one of the actions 
shown in the table in paragraph (b) of this section within 30 calendar 
days after the Regional Supervisor deems your EP submitted under Sec.  
550.231, or receives the last amendment to your proposed EP, whichever 
occurs later.

[[Page 64645]]

    (b) BOEM decision. By the deadline in paragraph (a) of this 
section, the Regional Supervisor will take one of the following 
actions:

----------------------------------------------------------------------------------------------------------------
 The regional supervisor will
            . . .                                 If . . .                               And then . . .
----------------------------------------------------------------------------------------------------------------
(1) Approve your EP,           It complies with all applicable requirements,   The Regional Supervisor will
                                                                                notify you in writing of the
                                                                                decision and may require you to
                                                                                meet certain conditions,
                                                                                including those to provide
                                                                                monitoring information.
(2) Require you to modify      The Regional Supervisor finds that it is        The Regional Supervisor will
 your proposed EP,              inconsistent with the lease, the Act, the       notify you in writing of the
                                regulations prescribed under the Act, or        decision and describe the
                                other Federal laws,                             modifications you must make to
                                                                                your proposed EP to ensure it
                                                                                complies with all applicable
                                                                                requirements.
(3) Disapprove your EP,        Your proposed activities would probably cause   (i) The Regional Supervisor will
                                serious harm or damage to life (including       notify you in writing of the
                                fish or other aquatic life); property; any      decision and describe the
                                mineral (in areas leased or not leased); the    reason(s) for disapproving your
                                National security or defense; or the marine,    EP.
                                coastal, or human environment; and you cannot  (ii) BOEM may cancel your lease
                                modify your proposed activities to avoid such   and compensate you under 43
                                condition(s),                                   U.S.C. 1334(a)(2)(C) and the
                                                                                implementing regulations in Sec.
                                                                                 Sec.   550.182, 550.184, and
                                                                                550.185 and 30 CFR 556.77.
----------------------------------------------------------------------------------------------------------------

Sec.  550.234  How do I submit a modified EP or resubmit a disapproved 
EP, and when will BOEM make a decision?

    (a) Modified EP. If the Regional Supervisor requires you to modify 
your proposed EP under Sec.  550.233(b)(2), you must submit the 
modification(s) to the Regional Supervisor in the same manner as for a 
new EP. You need submit only information related to the proposed 
modification(s).
    (b) Resubmitted EP. If the Regional Supervisor disapproves your EP 
under Sec.  550.233(b)(3), you may resubmit the disapproved EP if there 
is a change in the conditions that were the basis of its disapproval.
    (c) BOEM review and timeframe. The Regional Supervisor will use the 
performance standards in Sec.  550.202 to either approve, require you 
to further modify, or disapprove your modified or resubmitted EP. The 
Regional Supervisor will make a decision within 30 calendar days after 
the Regional Supervisor deems your modified or resubmitted EP to be 
submitted, or receives the last amendment to your modified or 
resubmitted EP, whichever occurs later.

Sec.  550.235  If a State objects to the EP's coastal zone consistency 
certification, what can I do?

    If an affected State objects to the coastal zone consistency 
certification accompanying your proposed EP within the timeframe 
prescribed in Sec.  550.233(a) or Sec.  550.234(c), you may do one of 
the following:
    (a) Amend your EP. Amend your EP to accommodate the State's 
objection and submit the amendment to the Regional Supervisor for 
approval. The amendment needs to only address information related to 
the State's objection.
    (b) Appeal. Appeal the State's objection to the Secretary of 
Commerce using the procedures in 15 CFR part 930, subpart H. The 
Secretary of Commerce will either:
    (1) Grant your appeal by finding, under section 307(c)(3)(B)(iii) 
of the CZMA (16 U.S.C. 1456(c)(3)(B)(iii)), that each activity 
described in detail in your EP is consistent with the objectives of the 
CZMA, or is otherwise necessary in the interest of National security; 
or
    (2) Deny your appeal, in which case you may amend your EP as 
described in paragraph (a) of this section.
    (c) Withdraw your EP. Withdraw your EP if you decide not to conduct 
your proposed exploration activities.

Contents of Development and Production Plans (DPP) and Development 
Operations Coordination Documents (DOCD)

Sec.  550.241  What must the DPP or DOCD include?

    Your DPP or DOCD must include the following:
    (a) Description, objectives, and schedule. A description, 
discussion of the objectives, and tentative schedule (from start to 
completion) of the development and production activities you propose to 
undertake. Examples of development and production activities include:
    (1) Development drilling;
    (2) Well test flaring;
    (3) Installation of production platforms, satellite structures, 
subsea wellheads and manifolds, and lease term pipelines (see 
definition at Sec.  550.105); and
    (4) Installation of production facilities and conduct of production 
operations.
    (b) Location. The location and water depth of each of your proposed 
wells and production facilities. Include a map showing the surface and 
bottom-hole location and water depth of each proposed well, the surface 
location of each production facility, and the locations of all 
associated drilling unit and construction barge anchors.
    (c) Drilling unit. A description of the drilling unit and 
associated equipment you will use to conduct your proposed development 
drilling activities. Include a brief description of its important 
safety and pollution prevention features, and a table indicating the 
type and the estimated maximum quantity of fuels and oil that will be 
stored on the facility (see definition of ``facility (3)'' under Sec.  
550.105).
    (d) Production facilities. A description of the production 
platforms, satellite structures, subsea wellheads and manifolds, lease 
term pipelines (see definition at Sec.  550.105), production 
facilities, umbilicals, and other facilities you will use to conduct 
your proposed development and production activities. Include a brief 
description of their important safety and pollution prevention 
features, and a table indicating the type and the estimated maximum 
quantity of fuels and oil that will be stored on the facility (see 
definition of ``facility (3)'' under Sec.  550.105).
    (e) Service fee. You must include payment of the service fee listed 
in Sec.  550.125.

Sec.  550.242  What information must accompany the DPP or DOCD?

    The following information must accompany your DPP or DOCD.
    (a) General information required by Sec.  550.243;
    (b) G&G information required by Sec.  550.244;
    (c) Hydrogen sulfide information required by Sec.  550.245;

[[Page 64646]]

    (d) Mineral resource conservation information required by Sec.  
550.246;
    (e) Biological, physical, and socioeconomic information required by 
Sec.  550.247;
    (f) Solid and liquid wastes and discharges information and cooling 
water intake information required by Sec.  550.248;
    (g) Air emissions information required by Sec.  550.249;
    (h) Oil and hazardous substance spills information required by 
Sec.  550.250;
    (i) Alaska planning information required by Sec.  550.251;
    (j) Environmental monitoring information required by Sec.  550.252;
    (k) Lease stipulations information required by Sec.  550.253;
    (l) Mitigation measures information required by Sec.  550.254;
    (m) Decommissioning information required by Sec.  550.255;
    (n) Related facilities and operations information required by Sec.  
550.256;
    (o) Support vessels and aircraft information required by Sec.  
550.257;
    (p) Onshore support facilities information required by Sec.  
550.258;
    (q) Sulphur operations information required by Sec.  550.259;
    (r) Coastal zone management information required by Sec.  550.260;
    (s) Environmental impact analysis information required by Sec.  
550.261; and
    (t) Administrative information required by Sec.  550.262.

Sec.  550.243  What general information must accompany the DPP or DOCD?

    The following general information must accompany your DPP or DOCD:
    (a) Applications and permits. A listing, including filing or 
approval status, of the Federal, State, and local application approvals 
or permits you must obtain to carry out your proposed development and 
production activities.
    (b) Drilling fluids. A table showing the projected amount, 
discharge rate, and chemical constituents for each type (i.e., water 
based, oil based, synthetic based) of drilling fluid you plan to use to 
drill your proposed development wells.
    (c) Production. The following production information:
    (1) Estimates of the average and peak rates of production for each 
type of production and the life of the reservoir(s) you intend to 
produce; and
    (2) The chemical and physical characteristics of the produced oil 
(see definition under 30 CFR 254.6) that you will handle or store at 
the facilities you will use to conduct your proposed development and 
production activities.
    (d) Chemical products. A table showing the name and brief 
description, quantities to be stored, storage method, and rates of 
usage of the chemical products you will use to conduct your proposed 
development and production activities. You need list only those 
chemical products you will store or use in quantities greater than the 
amounts defined as Reportable Quantities in 40 CFR part 302, or amounts 
specified by the Regional Supervisor.
    (e) New or unusual technology. A description and discussion of any 
new or unusual technology (see definition under Sec.  550.200) you will 
use to carry out your proposed development and production activities. 
In the public information copies of your DPP or DOCD, you may exclude 
any proprietary information from this description. In that case, 
include a brief discussion of the general subject matter of the omitted 
information. If you will not use any new or unusual technology to carry 
out your proposed development and production activities, include a 
statement so indicating.
    (f) Bonds, oil spill financial responsibility, and well control 
statements. Statements attesting that:
    (1) The activities and facilities proposed in your DPP or DOCD are 
or will be covered by an appropriate bond under 30 CFR part 556, 
subpart I;
    (2) You have demonstrated or will demonstrate oil spill financial 
responsibility for facilities proposed in your DPP or DOCD, according 
to 30 CFR part 553; and
    (3) You have or will have the financial capability to drill a 
relief well and conduct other emergency well control operations.
    (g) Suspensions of production or operations. A brief discussion of 
any suspensions of production or suspensions of operations that you 
anticipate may be necessary in the course of conducting your activities 
under the DPP or DOCD.
    (h) Blowout scenario. A scenario for a potential blowout of the 
proposed well in your DPP or DOCD that you expect will have the highest 
volume of liquid hydrocarbons. Include the estimated flow rate, total 
volume, and maximum duration of the potential blowout. Also, discuss 
the potential for the well to bridge over, the likelihood for surface 
intervention to stop the blowout, the availability of a rig to drill a 
relief well, and rig package constraints. Estimate the time it would 
take to drill a relief well.
    (i) Contact. The name, mailing address, (e-mail address if 
available), and telephone number of the person with whom the Regional 
Supervisor and the affected State(s) can communicate about your DPP or 
DOCD.

Sec.  550.244  What geological and geophysical (G&G) information must 
accompany the DPP or DOCD?

    The following G&G information must accompany your DPP or DOCD:
    (a) Geological description. A geological description of the 
prospect(s).
    (b) Structure contour maps. Current structure contour maps (depth-
based, expressed in feet subsea) showing depths of expected productive 
formations and the locations of proposed wells.
    (c) Two dimensional (2-D) or three-dimensional (3-D) seismic lines. 
Copies of migrated and annotated 2-D or 3-D seismic lines (with depth 
scale) intersecting at or near your proposed well locations. You are 
not required to conduct both 2-D and 3-D seismic surveys if you choose 
to conduct only one type of survey. If you have conducted both types of 
surveys, the Regional Supervisor may instruct you to submit the results 
of both surveys. You must interpret and display this information. 
Provide this information as an enclosure to only one proprietary copy 
of your DPP or DOCD.
    (d) Geological cross-sections. Interpreted geological cross-
sections showing the depths of expected productive formations.
    (e) Shallow hazards report. A shallow hazards report based on 
information obtained from a high-resolution geophysical survey, or a 
reference to such report if you have already submitted it to the 
Regional Supervisor.
    (f) Shallow hazards assessment. For each proposed well, an 
assessment of any seafloor and subsurface geologic and manmade features 
and conditions that may adversely affect your proposed drilling 
operations.
    (g) High resolution seismic lines. A copy of the high-resolution 
survey line closest to each of your proposed well locations. Because of 
its volume, provide this information as an enclosure to only one 
proprietary copy of your DPP or DOCD. You are not required to provide 
this information if the surface location of your proposed well has been 
approved in a previously submitted EP, DPP, or DOCD.
    (h) Stratigraphic column. A generalized biostratigraphic/
lithostratigraphic column from the surface to the total depth of each 
proposed well.
    (i) Time-versus-depth chart. A seismic travel time-versus-depth 
chart based on the appropriate velocity analysis in the area of 
interpretation and specifying the geodetic datum.
    (j) Geochemical information. A copy of any geochemical reports you 
used or generated.

[[Page 64647]]

    (k) Future G&G activities. A brief description of the G&G 
explorations and development G&G activities that you may conduct for 
lease or unit purposes after your DPP or DOCD is approved.

Sec.  550.245  What hydrogen sulfide (H2S) information must 
accompany the DPP or DOCD?

    The following H2S information, as applicable, must 
accompany your DPP or DOCD:
    (a) Concentration. The estimated concentration of any 
H2S you might encounter or handle while you conduct your 
proposed development and production activities.
    (b) Classification. Under 30 CFR 250.490(c), a request that the 
Regional Supervisor classify the area of your proposed development and 
production activities as either H2S absent, H2S 
present, or H2S unknown. Provide sufficient information to 
justify your request.
    (c) H 2S Contingency Plan. If you request that the 
Regional Supervisor classify the area of your proposed development and 
production activities as either H2S present or 
H2S unknown, an H2S Contingency Plan prepared 
under 30 CFR 250.490(f), or a reference to an approved or submitted 
H2S Contingency Plan that covers the proposed development 
and production activities.
    (d) Modeling report. (1) If you have determined or estimated that 
the concentration of any H2S you may encounter or handle 
while you conduct your development and production activities will be 
greater than 500 parts per million (ppm), you must:
    (i) Model a potential worst case H2S release from the 
facilities you will use to conduct your proposed development and 
production activities; and
    (ii) Include a modeling report or modeling results, or a reference 
to such report or results if you have already submitted it to the 
Regional Supervisor.
    (2) The analysis in the modeling report must be specific to the 
particular site of your development and production activities, and must 
consider any nearby human-occupied OCS facilities, shipping lanes, 
fishery areas, and other points where humans may be subject to 
potential exposure from an H2S release from your proposed 
activities.
    (3) If any H2S emissions are projected to affect an 
onshore location in concentrations greater than 10 ppm, the modeling 
analysis must be consistent with the EPA's risk management plan 
methodologies outlined in 40 CFR part 68.

Sec.  550.246  What mineral resource conservation information must 
accompany the DPP or DOCD?

    The following mineral resource conservation information, as 
applicable, must accompany your DPP or DOCD:
    (a) Technology and reservoir engineering practices and procedures. 
A description of the technology and reservoir engineering practices and 
procedures you will use to increase the ultimate recovery of oil and 
gas (e.g., secondary, tertiary, or other enhanced recovery practices). 
If you will not use enhanced recovery practices initially, provide an 
explanation of the methods you considered and the reasons why you are 
not using them.
    (b) Technology and recovery practices and procedures. A description 
of the technology and recovery practices and procedures you will use to 
ensure optimum recovery of oil and gas or sulphur.
    (c) Reservoir development. A discussion of exploratory well 
results, other reservoir data, proposed well spacing, completion 
methods, and other relevant well plan information.

Sec.  550.247  What biological, physical, and socioeconomic information 
must accompany the DPP or DOCD?

    If you obtain the following information in developing your DPP or 
DOCD, or if the Regional Supervisor requires you to obtain it, you must 
include a report, or the information obtained, or a reference to such a 
report or information if you have already submitted it to the Regional 
Supervisor, as accompanying information:
    (a) Biological environment reports. Site-specific information on 
chemosynthetic communities, federally listed threatened or endangered 
species, marine mammals protected under the MMPA, sensitive underwater 
features, marine sanctuaries, critical habitat designated under the 
ESA, or other areas of biological concern.
    (b) Physical environment reports. Site-specific meteorological, 
physical oceanographic, geotechnical reports, or archaeological reports 
(if required under Sec.  550.194).
    (c) Socioeconomic study reports. Socioeconomic information related 
to your proposed development and production activities.

Sec.  550.248  What solid and liquid wastes and discharges information 
and cooling water intake information must accompany the DPP or DOCD?

    The following solid and liquid wastes and discharges information 
and cooling water intake information must accompany your DPP or DOCD:
    (a) Projected wastes. A table providing the name, brief 
description, projected quantity, and composition of solid and liquid 
wastes (such as spent drilling fluids, drill cuttings, trash, sanitary 
and domestic wastes, produced waters, and chemical product wastes) 
likely to be generated by your proposed development and production 
activities. Describe:
    (1) The methods you used for determining this information; and
    (2) Your plans for treating, storing, and downhole disposal of 
these wastes at your facility location(s).
    (b) Projected ocean discharges. If any of your solid and liquid 
wastes will be discharged overboard or are planned discharges from 
manmade islands:
    (1) A table showing the name, projected amount, and rate of 
discharge for each waste type; and
    (2) A description of the discharge method (such as shunting through 
a downpipe, adding to a produced water stream, etc.) you will use.
    (c) National Pollutant Discharge Elimination System (NPDES) permit. 
(1) A discussion of how you will comply with the provisions of the 
applicable general NPDES permit that covers your proposed development 
and production activities; or
    (2) A copy of your application for an individual NPDES permit. 
Briefly describe the major discharges and methods you will use for 
compliance.
    (d) Modeling report. A modeling report or the modeling results (if 
you modeled the discharges of your projected solid or liquid wastes in 
developing your DPP or DOCD), or a reference to such report or results 
if you have already submitted it to the Regional Supervisor.
    (e) Projected cooling water intake. A table for each cooling water 
intake structure likely to be used by your proposed development and 
production activities that includes a brief description of the cooling 
water intake structure, daily water intake rate, water intake through-
screen velocity, percentage of water intake used for cooling water, 
mitigation measures for reducing impingement and entrainment of aquatic 
organisms, and biofouling prevention measures.

Sec.  550.249  What air emissions information must accompany the DPP or 
DOCD?

    The following air emissions information, as applicable, must 
accompany your DPP or DOCD:
    (a) Projected emissions. Tables showing the projected emissions of 
sulphur dioxide (SO2), particulate matter in the form of 
PM10 and PM2.5 when applicable, nitrogen oxides 
(NOX),

[[Page 64648]]

carbon monoxide (CO), and volatile organic compounds (VOC) that will be 
generated by your proposed development and production activities.
    (1) For each source on or associated with the facility you will use 
to conduct your proposed development and production activities, you 
must list:
    (i) The projected peak hourly emissions;
    (ii) The total annual emissions in tons per year;
    (iii) Emissions over the duration of the proposed development and 
production activities;
    (iv) The frequency and duration of emissions; and
    (v) The total of all emissions listed in paragraph (a)(1)(i) 
through (iv) of this section.
    (2) If your proposed production and development activities would 
result in an increase in the emissions of an air pollutant from your 
facility to an amount greater than the amount specified in your 
previously approved DPP or DOCD, you must show the revised emission 
rates for each source as well as the incremental change for each 
source.
    (3) You must provide the basis for all calculations, including 
engine size and rating, and applicable operational information.
    (4) You must base the projected emissions on the maximum rated 
capacity of the equipment and the maximum throughput of the facility 
you will use to conduct your proposed development and production 
activities under its physical and operational design.
    (5) If the specific drilling unit has not yet been determined, you 
must use the maximum emission estimates for the type of drilling unit 
you will use.
    (b) Emission reduction measures. A description of any proposed 
emission reduction measures, including the affected source(s), the 
emission reduction control technologies or procedures, the quantity of 
reductions to be achieved, and any monitoring system you propose to use 
to measure emissions.
    (c) Processes, equipment, fuels, and combustibles. A description of 
processes, processing equipment, combustion equipment, fuels, and 
storage units. You must include the frequency, duration, and maximum 
burn rate of any flaring activity.
    (d) Distance to shore. Identification of the distance of the site 
of your proposed development and production activities from the mean 
high water mark (mean higher high water mark on the Pacific coast) of 
the adjacent State.
    (e) Non-exempt facilities. A description of how you will comply 
with Sec.  550.303 when the projected emissions of SO2, PM, 
NOX, CO, or VOC that will be generated by your proposed 
development and production activities are greater than the respective 
emission exemption amounts ``E'' calculated using the formulas in Sec.  
550.303(d). When BOEM requires air quality modeling, you must use the 
guidelines in Appendix W of 40 CFR part 51 with a model approved by the 
Director. Submit the best available meteorological information and data 
consistent with the model(s) used.
    (f) Modeling report. A modeling report or the modeling results (if 
Sec.  550.303 requires you to use an approved air quality model to 
model projected air emissions in developing your DPP or DOCD), or a 
reference to such report or results if you have already submitted it to 
the Regional Supervisor.

Sec.  550.250  What oil and hazardous substance spills information must 
accompany the DPP or DOCD?

    The following information regarding potential spills of oil (see 
definition under 30 CFR 254.6) and hazardous substances (see definition 
under 40 CFR part 116), as applicable, must accompany your DPP or DOCD:
    (a) Oil spill response planning. The material required under 
paragraph (a)(1) or (a)(2) of this section:
    (1) An Oil Spill Response Plan (OSRP) for the facilities you will 
use to conduct your proposed development and production activities 
prepared according to the requirements of 30 CFR part 254, subpart B; 
or
    (2) Reference to your approved regional OSRP (see 30 CFR 254.3) to 
include:
    (i) A discussion of your regional OSRP;
    (ii) The location of your primary oil spill equipment base and 
staging area;
    (iii) The name(s) of your oil spill removal organization(s) for 
both equipment and personnel;
    (iv) The calculated volume of your worst case discharge scenario 
(see 30 CFR 254.26(a)), and a comparison of the appropriate worst case 
discharge scenario in your approved regional OSRP with the worst case 
discharge scenario that could result from your proposed development and 
production activities; and
    (v) A description of the worst case oil spill scenario that could 
result from your proposed development and production activities (see 30 
CFR 254.26(b), (c), (d), and (e)).
    (b) Modeling report. If you model a potential oil or hazardous 
substance spill in developing your DPP or DOCD, a modeling report or 
the modeling results, or a reference to such report or results if you 
have already submitted it to the Regional Supervisor.

Sec.  550.251  If I propose activities in the Alaska OCS Region, what 
planning information must accompany the DPP?

    If you propose development and production activities in the Alaska 
OCS Region, the following planning information must accompany your DPP:
    (a) Emergency plans. A description of your emergency plans to 
respond to a blowout, loss or disablement of a drilling unit, and loss 
of or damage to support craft; and
    (b) Critical operations and curtailment procedures. Critical 
operations and curtailment procedures for your development and 
production activities. The procedures must identify ice conditions, 
weather, and other constraints under which the development and 
production activities will either be curtailed or not proceed.

Sec.  550.252  What environmental monitoring information must accompany 
the DPP or DOCD?

    The following environmental monitoring information, as applicable, 
must accompany your DPP or DOCD:
    (a) Monitoring systems. A description of any existing and planned 
monitoring systems that are measuring, or will measure, environmental 
conditions or will provide project-specific data or information on the 
impacts of your development and production activities.
    (b) Incidental takes. If there is reason to believe that protected 
species may be incidentally taken by planned development and production 
activities, you must describe how you will monitor for incidental take 
of:
    (1) Threatened and endangered species listed under the ESA; and
    (2) Marine mammals, as appropriate, if you have not already 
received authorization for incidental take of marine mammals as may be 
necessary under the MMPA.
    (c) Flower Garden Banks National Marine Sanctuary (FGBNMS). If you 
propose to conduct development and production activities within the 
protective zones of the FGBNMS, a description of your provisions for 
monitoring the impacts of oil spill on the environmentally sensitive 
resources of the FGBNMS.

Sec.  550.253  What lease stipulations information must accompany the 
DPP or DOCD?

    A description of the measures you took, or will take, to satisfy 
the conditions of lease stipulations related

[[Page 64649]]

to your proposed development and production activities must accompany 
your DPP or DOCD.

Sec.  550.254  What mitigation measures information must accompany the 
DPP or DOCD?

    (a) If you propose to use any measures beyond those required by the 
regulations in this part to minimize or mitigate environmental impacts 
from your proposed development and production activities, a description 
of the measures you will use must accompany your DPP or DOCD.
    (b) If there is reason to believe that protected species may be 
incidentally taken by planned development and production activities, 
you must include mitigation measures designed to avoid or minimize that 
incidental take of:
    (1) Threatened and endangered species listed under the ESA; and
    (2) Marine mammals, as appropriate, if you have not already 
received authorization for incidental take as may be necessary under 
the MMPA.

Sec.  550.255  What decommissioning information must accompany the DPP 
or DOCD?

    A brief description of how you intend to decommission your wells, 
platforms, pipelines, and other facilities, and clear your site(s) must 
accompany your DPP or DOCD.

Sec.  550.256  What related facilities and operations information must 
accompany the DPP or DOCD?

    The following information regarding facilities and operations 
directly related to your proposed development and production activities 
must accompany your DPP or DOCD.
    (a) OCS facilities and operations. A description and location of 
any of the following that directly relate to your proposed development 
and production activities:
    (1) Drilling units;
    (2) Production platforms;
    (3) Right-of-way pipelines (including those that transport chemical 
products and produced water); and
    (4) Other facilities and operations located on the OCS (regardless 
of ownership).
    (b) Transportation system. A discussion of the transportation 
system that you will use to transport your production to shore, 
including:
    (1) Routes of any new pipelines;
    (2) Information concerning barges and shuttle tankers, including 
the storage capacity of the transport vessel(s), and the number of 
transfers that will take place per year;
    (3) Information concerning any intermediate storage or processing 
facilities;
    (4) An estimate of the quantities of oil, gas, or sulphur to be 
transported from your production facilities; and
    (5) A description and location of the primary onshore terminal.

Sec.  550.257  What information on the support vessels, offshore 
vehicles, and aircraft you will use must accompany the DPP or DOCD?

    The following information on the support vessels, offshore 
vehicles, and aircraft you will use must accompany your DPP or DOCD:
    (a) General. A description of the crew boats, supply boats, anchor 
handling vessels, tug boats, barges, ice management vessels, other 
vessels, offshore vehicles, and aircraft you will use to support your 
development and production activities. The description of vessels and 
offshore vehicles must estimate the storage capacity of their fuel 
tanks and the frequency of their visits to the facilities you will use 
to conduct your proposed development and production activities.
    (b) Air emissions. A table showing the source, composition, 
frequency, and duration of the air emissions likely to be generated by 
the support vessels, offshore vehicles, and aircraft you will use that 
will operate within 25 miles of the facilities you will use to conduct 
your proposed development and production activities.
    (c) Drilling fluids and chemical products transportation. A 
description of the transportation method and quantities of drilling 
fluids and chemical products (see Sec.  550.243(b) and (d)) you will 
transport from the onshore support facilities you will use to the 
facilities you will use to conduct your proposed development and 
production activities.
    (d) Solid and liquid wastes transportation. A description of the 
transportation method and a brief description of the composition, 
quantities, and destination(s) of solid and liquid wastes (see Sec.  
550.248(a)) you will transport from the facilities you will use to 
conduct your proposed development and production activities.
    (e) Vicinity map. A map showing the location of your proposed 
development and production activities relative to the shoreline. The 
map must depict the primary route(s) the support vessels and aircraft 
will use when traveling between the onshore support facilities you will 
use and the facilities you will use to conduct your proposed 
development and production activities.

Sec.  550.258  What information on the onshore support facilities you 
will use must accompany the DPP or DOCD?

    The following information on the onshore support facilities you 
will use must accompany your DPP or DOCD:
    (a) General. A description of the onshore facilities you will use 
to provide supply and service support for your proposed development and 
production activities (e.g., service bases and mud company docks).
    (1) Indicate whether the onshore support facilities are existing, 
to be constructed, or to be expanded; and
    (2) For DPPs only, provide a timetable for acquiring lands 
(including rights-of-way and easements) and constructing or expanding 
any of the onshore support facilities.
    (b) Air emissions. A description of the source, composition, 
frequency, and duration of the air emissions (attributable to your 
proposed development and production activities) likely to be generated 
by the onshore support facilities you will use.
    (c) Unusual solid and liquid wastes. A description of the quantity, 
composition, and method of disposal of any unusual solid and liquid 
wastes (attributable to your proposed development and production 
activities) likely to be generated by the onshore support facilities 
you will use. Unusual wastes are those wastes not specifically 
addressed in the relevant National Pollution Discharge Elimination 
System (NPDES) permit.
    (d) Waste disposal. A description of the onshore facilities you 
will use to store and dispose of solid and liquid wastes generated by 
your proposed development and production activities (see Sec.  
550.248(a)) and the types and quantities of such wastes.

Sec.  550.259  What sulphur operations information must accompany the 
DPP or DOCD?

    If you are proposing to conduct sulphur development and production 
activities, the following information must accompany your DPP or DOCD:
    (a) Bleedwater. A discussion of the bleedwater that will be 
generated by your proposed sulphur activities, including the measures 
you will take to mitigate the potential toxic or thermal impacts on the 
environment caused by the discharge of bleedwater.
    (b) Subsidence. An estimate of the degree of subsidence expected at 
various stages of your sulphur development and production activities, 
and a description of the measures you will take to mitigate the effects 
of subsidence on existing or potential oil and gas production, 
production

[[Page 64650]]

platforms, and production facilities, and to protect the environment.

Sec.  550.260  What Coastal Zone Management Act (CZMA) information must 
accompany the DPP or DOCD?

    The following CZMA information must accompany your DPP or DOCD:
    (a) Consistency certification. A copy of your consistency 
certification under section 307(c)(3)(B) of the CZMA (16 U.S.C. 
1456(c)(3)(B)) and 15 CFR 930.76(c) stating that the proposed 
development and production activities described in detail in this DPP 
or DOCD comply with (name of State(s)) approved coastal management 
program(s) and will be conducted in a manner that is consistent with 
such program(s); and
    (b) Other information. ``Information'' as required by 15 CFR 
930.76(a) and 15 CFR 930.58(a)(2)) and ``Analysis'' as required by 15 
CFR 930.58(a)(3).

Sec.  550.261  What environmental impact analysis (EIA) information 
must accompany the DPP or DOCD?

    The following EIA information must accompany your DPP or DOCD:
    (a) General requirements. Your EIA must:
    (1) Assess the potential environmental impacts of your proposed 
development and production activities;
    (2) Be project specific; and
    (3) Be as detailed as necessary to assist the Regional Supervisor 
in complying with the NEPA of 1969 (42 U.S.C. 4321 et seq.) and other 
relevant Federal laws such as the ESA and the MMPA.
    (b) Resources, conditions, and activities. Your EIA must describe 
those resources, conditions, and activities listed below that could be 
affected by your proposed development and production activities, or 
that could affect the construction and operation of facilities or 
structures or the activities proposed in your DPP or DOCD.
    (1) Meteorology, oceanography, geology, and shallow geological or 
manmade hazards;
    (2) Air and water quality;
    (3) Benthic communities, marine mammals, sea turtles, coastal and 
marine birds, fish and shellfish, and plant life;
    (4) Threatened or endangered species and their critical habitat;
    (5) Sensitive biological resources or habitats such as essential 
fish habitat, refuges, preserves, special management areas identified 
in coastal management programs, sanctuaries, rookeries, and calving 
grounds;
    (6) Archaeological resources;
    (7) Socioeconomic resources (including the approximate number, 
timing, and duration of employment of persons engaged in onshore 
support and construction activities), population (including the 
approximate number of people and families added to local onshore 
areas), existing offshore and onshore infrastructure (including major 
sources of supplies, services, energy, and water), types of contractors 
or vendors that may place a demand on local goods and services, land 
use, subsistence resources and harvest practices, recreation, 
recreational and commercial fishing (including seasons, location, and 
type), minority and lower income groups, and CZMA programs;
    (8) Coastal and marine uses such as military activities, shipping, 
and mineral exploration or development; and
    (9) Other resources, conditions, and activities identified by the 
Regional Supervisor.
    (c) Environmental impacts. Your EIA must:
    (1) Analyze the potential direct and indirect impacts (including 
those from accidents, cooling water intake structures, and those 
identified in relevant ESA biological opinions such as, but not limited 
to, those from noise, vessel collisions, and marine trash and debris) 
that your proposed development and production activities will have on 
the identified resources, conditions, and activities;
    (2) Describe the type, severity, and duration of these potential 
impacts and their biological, physical, and other consequences and 
implications;
    (3) Describe potential measures to minimize or mitigate these 
potential impacts;
    (4) Describe any alternatives to your proposed development and 
production activities that you considered while developing your DPP or 
DOCD, and compare the potential environmental impacts; and
    (5) Summarize the information you incorporate by reference.
    (d) Consultation. Your EIA must include a list of agencies and 
persons with whom you consulted, or with whom you will be consulting, 
regarding potential impacts associated with your proposed development 
and production activities.
    (e) References cited. Your EIA must include a list of the 
references that you cite in the EIA.

Sec.  550.262  What administrative information must accompany the DPP 
or DOCD?

    The following administrative information must accompany your DPP or 
DOCD:
    (a) Exempted information description (public information copies 
only). A description of the general subject matter of the proprietary 
information that is included in the proprietary copies of your DPP or 
DOCD or its accompanying information.
    (b) Bibliography.
    (1) If you reference a previously submitted EP, DPP, DOCD, study 
report, survey report, or other material in your DPP or DOCD or its 
accompanying information, a list of the referenced material; and
    (2) The location(s) where the Regional Supervisor can inspect the 
cited referenced material if you have not submitted it.

Review and Decision Process for the DPP or DOCD

Sec.  550.266  After receiving the DPP or DOCD, what will BOEM do?

    (a) Determine whether deemed submitted. Within 25 working days 
after receiving your proposed DPP or DOCD and its accompanying 
information, the Regional Supervisor will deem your DPP or DOCD 
submitted if:
    (1) The submitted information, including the information that must 
accompany the DPP or DOCD (refer to the list in Sec.  550.242), 
fulfills requirements and is sufficiently accurate;
    (2) You have provided all needed additional information (see Sec.  
550.201(b)); and
    (3) You have provided the required number of copies (see Sec.  
550.206(a)).
    (b) Identify problems and deficiencies. If the Regional Supervisor 
determines that you have not met one or more of the conditions in 
paragraph (a) of this section, the Regional Supervisor will notify you 
of the problem or deficiency within 25 working days after the Regional 
Supervisor receives your DPP or DOCD and its accompanying information. 
The Regional Supervisor will not deem your DPP or DOCD submitted until 
you have corrected all problems or deficiencies identified in the 
notice.
    (c) Deemed submitted notification. The Regional Supervisor will 
notify you when your DPP or DOCD is deemed submitted.

Sec.  550.267  What actions will BOEM take after the DPP or DOCD is 
deemed submitted?

    (a) State, local government, CZMA consistency, and other reviews. 
Within 2 working days after the Regional Supervisor deems your DPP or 
DOCD submitted under Sec.  550.266, the Regional Supervisor will use 
receipted mail or alternative method to send a public information copy 
of the DPP or DOCD

[[Page 64651]]

and its accompanying information to the following:
    (1) The Governor of each affected State. The Governor has 60 
calendar days after receiving your deemed-submitted DPP or DOCD to 
submit comments and recommendations. The Regional Supervisor will not 
consider comments and recommendations received after the deadline.
    (2) The executive of any affected local government who requests a 
copy. The executive of any affected local government has 60 calendar 
days after receipt of your deemed-submitted DPP or DOCD to submit 
comments and recommendations. The Regional Supervisor will not consider 
comments and recommendations received after the deadline. The executive 
of any affected local government must forward all comments and 
recommendations to the respective Governor before submitting them to 
the Regional Supervisor.
    (3) The CZMA agency of each affected State. The CZMA consistency 
review period under section 307(c)(3)(B)(ii) of the CZMA (16 
U.S.C.1456(c)(3)(B)(ii)) and 15 CFR 930.78 begins when the States CZMA 
agency receives a copy of your deemed-submitted DPP or DOCD, 
consistency certification, and required necessary data/information (see 
15 CFR 930.77(a)(1)).
    (b) General public. Within 2 working days after the Regional 
Supervisor deems your DPP or DOCD submitted under Sec.  550.266, the 
Regional Supervisor will make a public information copy of the DPP or 
DOCD and its accompanying information available for review to any 
appropriate interstate regional entity and the public at the 
appropriate BOEM Regional Public Information Office. Any interested 
Federal agency or person may submit comments and recommendations to the 
Regional Supervisor. Comments and recommendations must be received by 
the Regional Supervisor within 60 calendar days after the DPP or DOCD 
including its accompanying information is made available.
    (c) BOEM compliance review. The Regional Supervisor will review the 
development and production activities in your proposed DPP or DOCD to 
ensure that they conform to the performance standards in Sec.  550.202.
    (d) Amendments. During the review of your proposed DPP or DOCD, the 
Regional Supervisor may require you, or you may elect, to change your 
DPP or DOCD. If you elect to amend your DPP or DOCD, the Regional 
Supervisor may determine that your DPP or DOCD, as amended, is subject 
to the requirements of Sec.  550.266.

Sec.  550.268  How does BOEM respond to recommendations?

    (a) Governor. The Regional Supervisor will accept those 
recommendations from the Governor that provide a reasonable balance 
between the National interest and the well-being of the citizens of 
each affected State. The Regional Supervisor will explain in writing to 
the Governor the reasons for rejecting any of his or her 
recommendations.
    (b) Local governments and the public. The Regional Supervisor may 
accept recommendations from the executive of any affected local 
government or the public.
    (c) Availability. The Regional Supervisor will make all comments 
and recommendations available to the public upon request.

Sec.  550.269  How will BOEM evaluate the environmental impacts of the 
DPP or DOCD?

    The Regional Supervisor will evaluate the environmental impacts of 
the activities described in your proposed DPP or DOCD and prepare 
environmental documentation under the National Environmental Policy Act 
(NEPA) (42 U.S.C.4321 et seq.) and the implementing regulations (40 CFR 
parts 1500 through 1508).
    (a) Environmental impact statement (EIS) declaration. At least once 
in each OCS planning area (other than the Western and Central GOM 
Planning Areas), the Director will declare that the approval of a 
proposed DPP is a major Federal action, and BOEM will prepare an EIS.
    (b) Leases or units in the vicinity. Before or immediately after 
the Director determines that preparation of an EIS is required, the 
Regional Supervisor may require lessees and operators of leases or 
units in the vicinity of the proposed development and production 
activities for which DPPs have not been approved to submit information 
about preliminary plans for their leases or units.
    (c) Draft EIS. The Regional Supervisor will send copies of the 
draft EIS to the Governor of each affected State and to the executive 
of each affected local government who requests a copy. Additionally, 
when BOEM prepares a DPP EIS, and the Federally-approved CZMA program 
for an affected State requires a DPP NEPA document for use in 
determining consistency, the Regional Supervisor will forward a copy of 
the draft EIS to the State's CZMA agency. The Regional Supervisor will 
also make copies of the draft EIS available to any appropriate Federal 
agency, interstate regional entity, and the public.

Sec.  550.270  What decisions will BOEM make on the DPP or DOCD and 
within what timeframe?

    (a) Timeframe. The Regional Supervisor will act on your deemed-
submitted DPP or DOCD as follows:
    (1) The Regional Supervisor will make a decision within 60 calendar 
days after the latest of the day that:
    (i) The comment period provided in Sec.  550.267(a)(1), (a)(2), and 
(b) closes;
    (ii) The final EIS for a DPP is released or adopted; or
    (iii) The last amendment to your proposed DOCD is received by the 
Regional Supervisor.
    (2) Notwithstanding paragraph (a)(1) of this section, BOEM will not 
approve your DPP or DOCD until either:
    (i) All affected States with approved CZMA programs concur, or have 
been conclusively presumed to concur, with your DPP or DOCD consistency 
certification under section 307(c)(3)(B)(i) and (ii) of the CZMA (16 
U.S.C. 1456(c)(3)(B)(i) and (ii)); or
    (ii) The Secretary of Commerce has made a finding authorized by 
section 307(c)(3)(B)(iii) of the CZMA (16 U.S.C. 1456(c)(3)(B)(iii)) 
that each activity described in the DPP or DOCD is consistent with the 
objectives of the CZMA, or is otherwise necessary in the interest of 
National security.
    (b) BOEM decision. By the deadline in paragraph (a) of this 
section, the Regional Supervisor will take one of the following 
actions:

------------------------------------------------------------------------
     The regional
 supervisor will . . .         If . . .              And then . . .
------------------------------------------------------------------------
(1) Approve your DPP    It complies with all   The Regional Supervisor
 or DOCD,                applicable             will notify you in
                         requirements,          writing of the decision
                                                and may require you to
                                                meet certain conditions,
                                                including those to
                                                provide monitoring
                                                information.

[[Page 64652]]

 
(2) Require you to      It fails to make       The Regional Supervisor
 modify your proposed    adequate provisions    will notify you in
 DPP or DOCD,            for safety,            writing of the decision
                         environmental          and describe the
                         protection, or         modifications you must
                         conservation of        make to your proposed
                         natural resources or   DPP or DOCD to ensure it
                         otherwise does not     complies with all
                         comply with the        applicable requirements.
                         lease, the Act, the
                         regulations
                         prescribed under the
                         Act, or other
                         Federal laws,
(3) Disapprove your     Any of the reasons in  (i) The Regional
 DPP or DOCD,            Sec.   550.271         Supervisor will notify
                         apply,                 you in writing of the
                                                decision and describe
                                                the reason(s) for
                                                disapproving your DPP or
                                                DOCD; and
                                               (ii) BOEM may cancel your
                                                lease and compensate you
                                                under 43 U.S.C.
                                                1351(h)(2)(C) and the
                                                implementing regulations
                                                in Sec.  Sec.   550.183
                                                through 550.185 and 30
                                                CFR 556.77.
------------------------------------------------------------------------

Sec.  550.271  For what reasons will BOEM disapprove the DPP or DOCD?

    The Regional Supervisor will disapprove your proposed DPP or DOCD 
if one of the four reasons in this section applies:
    (a) Non-compliance. The Regional Supervisor determines that you 
have failed to demonstrate that you can comply with the requirements of 
the Outer Continental Shelf Lands Act, as amended (Act), implementing 
regulations, or other applicable Federal laws.
    (b) No consistency concurrence. (1) An affected State has not yet 
issued a final decision on your coastal zone consistency certification 
(see 15 CFR 930.78(a)); or
    (2) An affected State objects to your coastal zone consistency 
certification, and the Secretary of Commerce, under section 
307(c)(3)(B)(iii) of the CZMA (16 U.S.C. 1456(c)(3)(B)(iii)), has not 
found that each activity described in the DPP or DOCD is consistent 
with the objectives of the CZMA or is otherwise necessary in the 
interest of National security.
    (3) If the Regional Supervisor disapproved your DPP or DOCD for the 
sole reason that an affected State either has not yet issued a final 
decision on, or has objected to, your coastal zone consistency 
certification (see paragraphs (b)(1) and (2) in this section), the 
Regional Supervisor will approve your DPP or DOCD upon receipt of 
concurrence by the affected State, at the time concurrence of the 
affected State is conclusively presumed, or when the Secretary of 
Commerce makes a finding authorized by section 307(c)(3)(B)(iii) of the 
CZMA (16 U.S.C. 1456(c)(3)(B)(iii)) that each activity described in 
your DPP or DOCD is consistent with the objectives of the CZMA, or is 
otherwise necessary in the interest of National security. In that 
event, you do not need to resubmit your DPP or DOCD for approval under 
Sec.  550.273(b).
    (c) National security or defense conflicts. Your proposed 
activities would threaten National security or defense.
    (d) Exceptional circumstances. The Regional Supervisor determines 
because of exceptional geological conditions, exceptional resource 
values in the marine or coastal environment, or other exceptional 
circumstances that all of the following apply:
    (1) Implementing your DPP or DOCD would cause serious harm or 
damage to life (including fish and other aquatic life), property, any 
mineral deposits (in areas leased or not leased), the National security 
or defense, or the marine, coastal, or human environment;
    (2) The threat of harm or damage will not disappear or decrease to 
an acceptable extent within a reasonable period of time; and
    (3) The advantages of disapproving your DPP or DOCD outweigh the 
advantages of development and production.

Sec.  550.272  If a State objects to the DPP's or DOCD's coastal zone 
consistency certification, what can I do?

    If an affected State objects to the coastal zone consistency 
certification accompanying your proposed or disapproved DPP or DOCD, 
you may do one of the following:
    (a) Amend or resubmit your DPP or DOCD. Amend or resubmit your DPP 
or DOCD to accommodate the State's objection and submit the amendment 
or resubmittal to the Regional Supervisor for approval. The amendment 
or resubmittal needs to only address information related to the State's 
objections.
    (b) Appeal. Appeal the State's objection to the Secretary of 
Commerce using the procedures in 15 CFR part 930, subpart H. The 
Secretary of Commerce will either:
    (1) Grant your appeal by finding under section 307(c)(3)(B)(iii) of 
the CZMA (16 U.S.C.1456(c)(3)(B)(iii)) that each activity described in 
detail in your DPP or DOCD is consistent with the objectives of the 
CZMA, or is otherwise necessary in the interest of National security; 
or
    (2) Deny your appeal, in which case you may amend or resubmit your 
DPP or DOCD, as described in paragraph (a) of this section.
    (c) Withdraw your DPP or DOCD. Withdraw your DPP or DOCD if you 
decide not to conduct your proposed development and production 
activities.

Sec.  550.273  How do I submit a modified DPP or DOCD or resubmit a 
disapproved DPP or DOCD?

    (a) Modified DPP or DOCD. If the Regional Supervisor requires you 
to modify your proposed DPP or DOCD under Sec.  550.270(b)(2), you must 
submit the modification(s) to the Regional Supervisor in the same 
manner as for a new DPP or DOCD. You need submit only information 
related to the proposed modification(s).
    (b) Resubmitted DPP or DOCD. If the Regional Supervisor disapproves 
your DPP or DOCD under Sec.  550.270(b)(3), and except as provided in 
Sec.  550.271(b)(3), you may resubmit the disapproved DPP or DOCD if 
there is a change in the conditions that were the basis of its 
disapproval.
    (c) BOEM review and timeframe. The Regional Supervisor will use the 
performance standards in Sec.  550.202 to either approve, require you 
to further modify, or disapprove your modified or resubmitted DPP or 
DOCD. The Regional Supervisor will make a decision within 60 calendar 
days after the Regional Supervisor deems your modified or resubmitted 
DPP or DOCD to be submitted, or receives the last amendment to your 
modified or resubmitted DPP or DOCD, whichever occurs later.

[[Page 64653]]

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

Sec.  550.280  How must I conduct activities under the approved EP, 
DPP, or DOCD?

    (a) Compliance. You must conduct all of your lease and unit 
activities according to your approved EP, DPP, or DOCD and any approval 
conditions. If you fail to comply with your approved EP, DPP, or DOCD:
    (1) You may be subject to BOEM enforcement action, including civil 
penalties; and
    (2) The lease(s) involved in your EP, DPP, or DOCD may be forfeited 
or cancelled under 43 U.S.C. 1334(c) or (d). If this happens, you will 
not be entitled to compensation under Sec.  550.185(b) and 30 CFR 
556.77.
    (b) Emergencies. Nothing in this subpart or in your approved EP, 
DPP, or DOCD relieves you of, or limits your responsibility to take 
appropriate measures to meet emergency situations. In an emergency 
situation, the Regional Supervisor may approve or require departures 
from your approved EP, DPP, or DOCD.

Sec.  550.281  What must I do to conduct activities under the approved 
EP, DPP, or DOCD?

    (a) Approvals and permits. Before you conduct activities under your 
approved EP, DPP, or DOCD you must obtain the following approvals and 
or permits, as applicable, from the District Manager or BSEE Regional 
Supervisor:
    (1) Approval of applications for permits to drill (APDs) (see 30 
CFR 250.410);
    (2) Approval of production safety systems (see 30 CFR 250.800);
    (3) Approval of new platforms and other structures (or major 
modifications to platforms and other structures) (see 30 CFR 250.905);
    (4) Approval of applications to install lease term pipelines (see 
30 CFR 250.1007); and
    (5) Other permits, as required by applicable law.
    (b) Conformance. The activities proposed in these applications and 
permits must conform to the activities described in detail in your 
approved EP, DPP, or DOCD.
    (c) Separate State CZMA consistency review. APDs, and other 
applications for licenses, approvals, or permits to conduct activities 
under your approved EP, DPP, or DOCD including those identified in 
paragraph (a) of this section, are not subject to separate State CZMA 
consistency review.
    (d) Approval restrictions for permits for activities conducted 
under EPs. The Regional Supervisor will not approve any APDs or other 
applications for licenses, approvals, or permits under your approved EP 
until either:
    (1) All affected States with approved coastal zone management 
programs concur, or are conclusively presumed to concur, with the 
coastal zone consistency certification accompanying your EP under 
section 307(c)(3)(B)(i) and (ii) of the CZMA (16 U.S.C. 
1456(c)(3)(B)(i) and (ii)); or
    (2) The Secretary of Commerce finds, under section 
307(c)(3)(B)(iii) of the CZMA (16 U.S.C.1456(c)(3)(B)(iii)) that each 
activity covered by the EP is consistent with the objectives of the 
CZMA or is otherwise necessary in the interest of National security;
    (3) If an affected State objects to the coastal zone consistency 
certification accompanying your approved EP after BOEM has approved 
your EP, you may either:
    (i) Revise your EP to accommodate the State's objection and submit 
the revision to the Regional Supervisor for approval; or
    (ii) Appeal the State's objection to the Secretary of Commerce 
using the procedures in 15 CFR part 930, subpart H. The Secretary of 
Commerce will either:
    (A) Grant your appeal by making the finding described in paragraph 
(d)(2) of this section; or
    (B) Deny your appeal, in which case you may revise your EP as 
described in paragraph (d)(3)(i) of this section.

Sec.  550.282  Do I have to conduct post-approval monitoring?

    After approving your EP, DPP, or DOCD, the Regional Supervisor may 
direct you to conduct monitoring programs, including monitoring in 
accordance with the ESA and the MMPA. You must retain copies of all 
monitoring data obtained or derived from your monitoring programs and 
make them available to the BOEM upon request. The Regional Supervisor 
may require you to:
    (a) Monitoring plans. Submit monitoring plans for approval before 
you begin the work; and
    (b) Monitoring reports. Prepare and submit reports that summarize 
and analyze data and information obtained or derived from your 
monitoring programs. The Regional Supervisor will specify requirements 
for preparing and submitting these reports.

Sec.  550.283  When must I revise or supplement the approved EP, DPP, 
or DOCD?

    (a) Revised OCS plans. You must revise your approved EP, DPP, or 
DOCD when you propose to:
    (1) Change the type of drilling rig (e.g., jack-up, platform rig, 
barge, submersible, semisubmersible, or drillship), production facility 
(e.g., caisson, fixed platform with piles, tension leg platform), or 
transportation mode (e.g., pipeline, barge);
    (2) Change the surface location of a well or production platform by 
a distance more than that specified by the Regional Supervisor;
    (3) Change the type of production or significantly increase the 
volume of production or storage capacity;
    (4) Increase the emissions of an air pollutant to an amount that 
exceeds the amount specified in your approved EP, DPP, or DOCD;
    (5) Significantly increase the amount of solid or liquid wastes to 
be handled or discharged;
    (6) Request a new H2S area classification, or increase 
the concentration of H2S to a concentration greater than 
that specified by the Regional Supervisor;
    (7) Change the location of your onshore support base either from 
one State to another or to a new base or a base requiring expansion; or
    (8) Change any other activity specified by the Regional Supervisor.
    (b) Supplemental OCS plans. You must supplement your approved EP, 
DPP, or DOCD when you propose to conduct activities on your lease(s) or 
unit that require approval of a license or permit which is not 
described in your approved EP, DPP, or DOCD. These types of changes are 
called supplemental OCS plans.

Sec.  550.284  How will BOEM require revisions to the approved EP, DPP, 
or DOCD?

    (a) Periodic review. The Regional Supervisor will periodically 
review the activities you conduct under your approved EP, DPP, or DOCD 
and may require you to submit updated information on your activities. 
The frequency and extent of this review will be based on the 
significance of any changes in available information and onshore or 
offshore conditions affecting, or affected by, the activities in your 
approved EP, DPP, or DOCD.
    (b) Results of review. The Regional Supervisor may require you to 
revise your approved EP, DPP, or DOCD based on this review. In such 
cases, the Regional Supervisor will inform you of the reasons for the 
decision.

Sec.  550.285  How do I submit revised and supplemental EPs, DPPs, and 
DOCDs?

    (a) Submittal. You must submit to the Regional Supervisor any 
revisions and supplements to approved EPs, DPPs, or DOCDs for approval, 
whether you

[[Page 64654]]

initiate them or the Regional Supervisor orders them.
    (b) Information. Revised and supplemental EPs, DPPs, and DOCDs need 
include only information related to or affected by the proposed 
changes, including information on changes in expected environmental 
impacts.
    (c) Procedures. All supplemental EPs, DPPs, and DOCDs, and those 
revised EPs, DPPs, and DOCDs that the Regional Supervisor determines 
are likely to result in a significant change in the impacts previously 
identified and evaluated, are subject to all of the procedures under 
Sec. Sec.  550.231 through 550.235 for EPs and Sec. Sec.  550.266 
through 550.273 for DPPs and DOCDs.

Sec. Sec.  550.286-550.295  [Reserved]

Conservation Information Documents (CID)

Sec.  550.296  When and how must I submit a CID or a revision to a CID?

    (a) You must submit one original and two copies of a CID to the 
appropriate OCS Region at the same time you first submit your DOCD or 
DPP for any development of a lease or leases located in water depths 
greater than 400 meters (1,312 feet). You must also submit a CID for a 
Supplemental DOCD or DPP when requested by the Regional Supervisor. The 
submission of your CID must be accompanied by payment of the service 
fee listed in Sec.  550.125.
    (b) If you decide not to develop a reservoir you committed to 
develop in your CID, you must submit one original and two copies of a 
revision to the CID to the appropriate OCS Region. The revision to the 
CID must be submitted within 14 calendar days after making your 
decision not to develop the reservoir and before the reservoir is 
bypassed. The Regional Supervisor will approve or disapprove any such 
revision to the original CID. If the Regional Supervisor disapproves 
the revision, you must develop the reservoir as described in the 
original CID.

Sec.  550.297  What information must a CID contain?

    (a) You must base the CID on wells drilled before your CID 
submittal that define the extent of the reservoirs. You must notify 
BOEM of any well that is drilled to total depth during the CID 
evaluation period and you may be required to update your CID.
    (b) You must include all of the following information if available. 
Information must be provided for each hydrocarbon-bearing reservoir 
that is penetrated by a well that would meet the producibility 
requirements of Sec.  550.115 or Sec.  550.116:
    (1) General discussion of the overall development of the reservoir;
    (2) Summary spreadsheets of well log data and reservoir parameters 
(i.e., sand tops and bases, fluid contacts, net pay, porosity, water 
saturations, pressures, formation volume factor);
    (3) Appropriate well logs, including digital well log (i.e., gamma 
ray, resistivity, neutron, density, sonic, caliper curves) curves in an 
acceptable digital format;
    (4) Sidewall core/whole core and pressure-volume-temperature 
analysis;
    (5) Structure maps, with the existing and proposed penetration 
points and subsea depths for all wells penetrating the reservoirs, 
fluid contacts (or the lowest or highest known levels in the absence of 
actual contacts), reservoir boundaries, and the scale of the map;
    (6) Interpreted structural cross sections and corresponding 
interpreted seismic lines or block diagrams, as necessary, that include 
all current wellbores and planned wellbores on the leases or units to 
be developed, the reservoir boundaries, fluid contacts, depth scale, 
stratigraphic positions, and relative biostratigraphic ages;
    (7) Isopach maps of each reservoir showing the net feet of pay for 
each well within the reservoir identified at the penetration point, 
along with the well name, labeled contours, and scale;
    (8) Estimates of original oil and gas in-place and anticipated 
recoverable oil and gas reserves, all reservoir parameters, and risk 
factors and assumptions;
    (9) Plat map at the same scale as the structure maps with existing 
and proposed well paths, as well as existing and proposed penetrations;
    (10) Wellbore schematics indicating proposed perforations;
    (11) Proposed wellbore utility chart showing all existing and 
proposed wells, with proposed completion intervals indicated for each 
borehole;
    (12) Appropriate pressure data, specified by date, and whether 
estimated or measured;
    (13) Description of reservoir development strategies;
    (14) Description of the enhanced recovery practices you will use 
or, if you do not plan to use such practices, an explanation of the 
methods you considered and reasons you do not intend to use them;
    (15) For each reservoir you do not intend to develop:
    (i) A statement explaining the reason(s) you will not develop the 
reservoir, and
    (ii) Economic justification, including costs, recoverable reserve 
estimate, production profiles, and pricing assumptions; and
    (16) Any other appropriate data you used in performing your 
reservoir evaluations and preparing your reservoir development 
strategies.

Sec.  550.298  How long will BOEM take to evaluate and make a decision 
on the CID?

    (a) The Regional Supervisor will make a decision within 150 
calendar days of receiving your CID. If BOEM does not act within 150 
calendar days, your CID is considered approved.
    (b) BOEM may suspend the 150-calendar-day evaluation period if 
there is missing, inconclusive, or inaccurate data, or when a well 
reaches total depth during the evaluation period. BOEM may also suspend 
the evaluation period when a well penetrating a hydrocarbon-bearing 
structure reaches total depth during the evaluation period and the data 
from that well is needed for the CID. You will receive written 
notification from the Regional Supervisor describing the additional 
information that is needed, and the evaluation period will resume once 
BOEM receives the requested information.
    (c) The Regional Supervisor will approve or deny your CID request 
based on your commitment to develop economically producible reservoirs 
according to sound conservation, engineering, and economic practices.

Sec.  550.299  What operations require approval of the CID?

    You may not begin production before you receive BOEM approval of 
the CID.

Subpart C--Pollution Prevention and Control

Sec. Sec.  550.300-550.301  [Reserved]

Sec.  550.302  Definitions concerning air quality.

    For purposes of Sec. Sec.  550.303 and 550.304 of this part:
    Air pollutant means any combination of agents for which the 
Environmental Protection Agency (EPA) has established, pursuant to 
section 109 of the Clean Air Act, national primary or secondary ambient 
air quality standards.
    Attainment area means, for any air pollutant, an area which is 
shown by monitored data or which is calculated by air quality modeling 
(or other methods determined by the Administrator of EPA to be 
reliable) not to exceed any primary or secondary ambient air quality 
standards established by EPA.
    Best available control technology (BACT) means an emission 
limitation based on the maximum degree of reduction for each air 
pollutant subject to regulation, taking into account

[[Page 64655]]

energy, environmental and economic impacts, and other costs. The BACT 
shall be verified on a case-by-case basis by the Regional Supervisor 
and may include reductions achieved through the application of 
processes, systems, and techniques for the control of each air 
pollutant.
    Emission offsets mean emission reductions obtained from facilities, 
either onshore or offshore, other than the facility or facilities 
covered by the proposed Exploration Plan or Development and Production 
Plan.
    Existing facility is an OCS facility described in an Exploration 
Plan or a Development and Production Plan submitted or approved prior 
to June 2, 1980.
    Facility means any installation or device permanently or 
temporarily attached to the seabed which is used for exploration, 
development, and production activities for oil, gas, or sulphur and 
which emits or has the potential to emit any air pollutant from one or 
more sources. All equipment directly associated with the installation 
or device shall be considered part of a single facility if the 
equipment is dependent on, or affects the processes of, the 
installation or device. During production, multiple installations or 
devices will be considered to be a single facility if the installations 
or devices are directly related to the production of oil, gas, or 
sulphur at a single site. Any vessel used to transfer production from 
an offshore facility shall be considered part of the facility while 
physically attached to it.
    Nonattainment area means, for any air pollutant, an area which is 
shown by monitored data or which is calculated by air quality modeling 
(or other methods determined by the Administrator of EPA to be 
reliable) to exceed any primary or secondary ambient air quality 
standard established by EPA.
    Projected emissions mean emissions, either controlled or 
uncontrolled, from a source(s).
    Source means an emission point. Several sources may be included 
within a single facility.
    Temporary facility means activities associated with the 
construction of platforms offshore or with facilities related to 
exploration for or development of offshore oil and gas resources which 
are conducted in one location for less than 3 years.
    Volatile organic compound (VOC) means any organic compound which is 
emitted to the atmosphere as a vapor. The unreactive compounds are 
exempt from the above definition.

Sec.  550.303  Facilities described in a new or revised Exploration 
Plan or Development and Production Plan.

    (a) New plans. All Exploration Plans and Development and Production 
Plans shall include the information required to make the necessary 
findings under paragraphs (d) through (i) of this section, and the 
lessee shall comply with the requirements of this section as necessary.
    (b) Applicability of Sec.  550.303 to existing facilities. (1) The 
Regional Supervisor may review any Exploration Plan or Development and 
Production Plan to determine whether any facility described in the plan 
should be subject to review under this section and has the potential to 
significantly affect the air quality of an onshore area. To make these 
decisions, the Regional Supervisor shall consider the distance of the 
facility from shore, the size of the facility, the number of sources 
planned for the facility and their operational status, and the air 
quality status of the onshore area.
    (2) For a facility identified by the Regional Supervisor in 
paragraph (b)(1) of this section, the Regional Supervisor shall require 
the lessee to refer to the information required in Sec.  550.218 or 
Sec.  550.249 of this part and to submit only that information required 
to make the necessary findings under paragraphs (d) through (i) of this 
section. The lessee shall submit this information within 120 days of 
the Regional Supervisor's determination or within a longer period of 
time at the discretion of the Regional Supervisor. The lessee shall 
comply with the requirements of this section as necessary.
    (c) Revised facilities. All revised Exploration Plans and 
Development and Production Plans shall include the information required 
to make the necessary findings under paragraphs (d) through (i) of this 
section. The lessee shall comply with the requirements of this section 
as necessary.
    (d) Exemption formulas. To determine whether a facility described 
in a new, modified, or revised Exploration Plan or Development and 
Production Plan is exempt from further air quality review, the lessee 
shall use the highest annual-total amount of emissions from the 
facility for each air pollutant calculated in Sec.  550.249(a) or Sec.  
550.218(a) of this part and compare these emissions to the emission 
exemption amount ``E'' for each air pollutant calculated using the 
following formulas: E=3400D \2/3\ for carbon monoxide (CO); and E=33.3D 
for total suspended particulates (TSP), sulphur dioxide 
(SO2), nitrogen oxides (NOX), and VOC (where E is 
the emission exemption amount expressed in tons per year, and D is the 
distance of the proposed facility from the closest onshore area of a 
State expressed in statute miles). If the amount of these projected 
emissions is less than or equal to the emission exemption amount ``E'' 
for the air pollutant, the facility is exempt from further air quality 
review required under paragraphs (e) through (i) of this section.
    (e) Significance levels. For a facility not exempt under paragraph 
(d) of this section for air pollutants other than VOC, the lessee shall 
use an approved air quality model to determine whether the projected 
emissions of those air pollutants from the facility result in an 
onshore ambient air concentration above the following significance 
levels:

                                Significance Levels--Air Pollutant Concentrations
                                                 [[micro]g/m\3\]
----------------------------------------------------------------------------------------------------------------
                                                              Averaging time (hours)
          Air pollutant          -------------------------------------------------------------------------------
                                      Annual            24               8               3               1
----------------------------------------------------------------------------------------------------------------
SO2.............................               1               5  ..............              25  ..............
TSP.............................               1               5  ..............  ..............  ..............
NO2.............................               1  ..............  ..............  ..............  ..............
CO..............................  ..............  ..............             500  ..............           2,000
----------------------------------------------------------------------------------------------------------------

    (f) Significance determinations. (1) The projected emissions of any 
air pollutant other than VOC from any facility which result in an 
onshore ambient air concentration above the significance level 
determined under

[[Page 64656]]

paragraph (e) of this section for that air pollutant, shall be deemed 
to significantly affect the air quality of the onshore area for that 
air pollutant.
    (2) The projected emissions of VOC from any facility which is not 
exempt under paragraph (d) of this section for that air pollutant shall 
be deemed to significantly affect the air quality of the onshore area 
for VOC.
    (g) Controls required. (1) The projected emissions of any air 
pollutant other than VOC from any facility, except a temporary 
facility, which significantly affect the quality of a nonattainment 
area, shall be fully reduced. This shall be done through the 
application of BACT and, if additional reductions are necessary, 
through the application of additional emission controls or through the 
acquisition of offshore or onshore offsets.
    (2) The projected emissions of any air pollutant other than VOC 
from any facility which significantly affect the air quality of an 
attainment or unclassifiable area shall be reduced through the 
application of BACT.
    (i) (A) Except for temporary facilities, the lessee also shall use 
an approved air quality model to determine whether the emissions of TSP 
or SO2 that remain after the application of BACT cause the 
following maximum allowable increases over the baseline concentrations 
established in 40 CFR 52.21 to be exceeded in the attainment or 
unclassifiable area:

                                    Maximum Allowable Concentration Increases
                                                 [[micro]g/m\3\]
----------------------------------------------------------------------------------------------------------------
                                                                                  Averaging times
                                                                 -----------------------------------------------
                          Air pollutant                             Annual mean       24-hour         3-hour
                                                                        \1\           maximum         maximum
----------------------------------------------------------------------------------------------------------------
Class I:
    TSP.........................................................               5              10  ..............
    SO2.........................................................               2               5              25
Class II:
    TSP.........................................................              19              37  ..............
    SO2.........................................................              20              91             512
Class III:
    TSP.........................................................              37              75  ..............
    SO2.........................................................              40             182             700
----------------------------------------------------------------------------------------------------------------
\1\ For TSP--geometric; For SO2--arithmetric.

    (B) No concentration of an air pollutant shall exceed the 
concentration permitted under the national secondary ambient air 
quality standard or the concentration permitted under the national 
primary air quality standard, whichever concentration is lowest for the 
air pollutant for the period of exposure. For any period other than the 
annual period, the applicable maximum allowable increase may be 
exceeded during one such period per year at any one onshore location.
    (ii) If the maximum allowable increases are exceeded, the lessee 
shall apply whatever additional emission controls are necessary to 
reduce or offset the remaining emissions of TSP or SO2 so 
that concentrations in the onshore ambient air of an attainment or 
unclassifiable area do not exceed the maximum allowable increases.
    (3)(i) The projected emissions of VOC from any facility, except a 
temporary facility, which significantly affect the onshore air quality 
of a nonattainment area shall be fully reduced. This shall be done 
through the application of BACT and, if additional reductions are 
necessary, through the application of additional emission controls or 
through the acquisition of offshore or onshore offsets.
    (ii) The projected emissions of VOC from any facility which 
significantly affect the onshore air quality of an attainment area 
shall be reduced through the application of BACT.
    (4)(i) If projected emissions from a facility significantly affect 
the onshore air quality of both a nonattainment and an attainment or 
unclassifiable area, the regulatory requirements applicable to 
projected emissions significantly affecting a nonattainment area shall 
apply.
    (ii) If projected emissions from a facility significantly affect 
the onshore air quality of more than one class of attainment area, the 
lessee must reduce projected emissions to meet the maximum allowable 
increases specified for each class in paragraph (g)(2)(i) of this 
section.
    (h) Controls required on temporary facilities. The lessee shall 
apply BACT to reduce projected emissions of any air pollutant from a 
temporary facility which significantly affects the air quality of an 
onshore area of a State.
    (i) Emission offsets. When emission offsets are to be obtained, the 
lessee must demonstrate that the offsets are equivalent in nature and 
quantity to the projected emissions that must be reduced after the 
application of BACT; a binding commitment exists between the lessee and 
the owner or owners of the source or sources; the appropriate air 
quality control jurisdiction has been notified of the need to revise 
the State Implementation Plan to include the information regarding the 
offsets; and the required offsets come from sources which affect the 
air quality of the area significantly affected by the lessee's offshore 
operations.
    (j) Review of facilities with emissions below the exemption amount. 
If, during the review of a new, modified, or revised Exploration Plan 
or Development and Production Plan, the Regional Supervisor determines 
or an affected State submits information to the Regional Supervisor 
which demonstrates, in the judgment of the Regional Supervisor, that 
projected emissions from an otherwise exempt facility will, either 
individually or in combination with other facilities in the area, 
significantly affect the air quality of an onshore area, then the 
Regional Supervisor shall require the lessee to submit additional 
information to determine whether emission control measures are 
necessary. The lessee shall be given the opportunity to present 
information to the Regional Supervisor which demonstrates that the 
exempt facility is not significantly affecting the air quality of an 
onshore area of the State.
    (k) Emission monitoring requirements. The lessee shall monitor, in 
a manner approved or prescribed by the Regional Supervisor, emissions 
from the facility. The lessee shall submit this information monthly in 
a manner and form

[[Page 64657]]

approved or prescribed by the Regional Supervisor.
    (l) Collection of meteorological data. The Regional Supervisor may 
require the lessee to collect, for a period of time and in a manner 
approved or prescribed by the Regional Supervisor, and submit 
meteorological data from a facility.

Sec.  550.304  Existing facilities.

    (a) Process leading to review of an existing facility. (1) An 
affected State may request that the Regional Supervisor supply basic 
emission data from existing facilities when such data are needed for 
the updating of the State's emission inventory. In submitting the 
request, the State must demonstrate that similar offshore and onshore 
facilities in areas under the State's jurisdiction are also included in 
the emission inventory.
    (2) The Regional Supervisor may require lessees of existing 
facilities to submit basic emission data to a State submitting a 
request under paragraph (a)(1) of this section.
    (3) The State submitting a request under paragraph (a)(1) of this 
section may submit information from its emission inventory which 
indicates that emissions from existing facilities may be significantly 
affecting the air quality of the onshore area of the State. The lessee 
shall be given the opportunity to present information to the Regional 
Supervisor which demonstrates that the facility is not significantly 
affecting the air quality of the State.
    (4) The Regional Supervisor shall evaluate the information 
submitted under paragraph (a)(3) of this section and shall determine, 
based on the basic emission data, available meteorological data, and 
the distance of the facility or facilities from the onshore area, 
whether any existing facility has the potential to significantly affect 
the air quality of the onshore area of the State.
    (5) If the Regional Supervisor determines that no existing facility 
has the potential to significantly affect the air quality of the 
onshore area of the State submitting information under paragraph (a)(3) 
of this section, the Regional Supervisor shall notify the State of and 
explain the reasons for this finding.
    (6) If the Regional Supervisor determines that an existing facility 
has the potential to significantly affect the air quality of an onshore 
area of the State submitting information under paragraph (a)(3) of this 
section, the Regional Supervisor shall require the lessee to refer to 
the information requirements under Sec.  550.218 or Sec.  550.249 of 
this part and submit only that information required to make the 
necessary findings under paragraphs (b) through (e) of this section. 
The lessee shall submit this information within 120 days of the 
Regional Supervisor's determination or within a longer period of time 
at the discretion of the Regional Supervisor. The lessee shall comply 
with the requirements of this section as necessary.
    (b) Exemption formulas. To determine whether an existing facility 
is exempt from further air quality review, the lessee shall use the 
highest annual total amount of emissions from the facility for each air 
pollutant calculated in Sec.  550.218(a) or Sec.  550.249(a) of this 
part and compare these emissions to the emission exemption amount ``E'' 
for each air pollutant calculated using the following formulas: E = 
3400D2/3for CO; and E = 33.3D for TSP, SO2, 
NOX, and VOC (where E is the emission exemption amount 
expressed in tons per year, and D is the distance of the facility from 
the closest onshore area of the State expressed in statute miles). If 
the amount of projected emissions is less than or equal to the emission 
exemption amount ``E'' for the air pollutant, the facility is exempt 
for that air pollutant from further air quality review required under 
paragraphs (c) through (e) of this section.
    (c) Significance levels. For a facility not exempt under paragraph 
(b) of this section for air pollutants other than VOC, the lessee shall 
use an approved air quality model to determine whether projected 
emissions of those air pollutants from the facility result in an 
onshore ambient air concentration above the following significance 
levels:

                                Significance Levels--Air Pollutant Concentrations
                                                  [[mu]G/M\3\]
----------------------------------------------------------------------------------------------------------------
                                                              Averaging time (hours)
          Air pollutant          -------------------------------------------------------------------------------
                                      Annual            24               8               3               1
----------------------------------------------------------------------------------------------------------------
SO2.............................               1               5  ..............              25  ..............
TSP.............................               1               5  ..............  ..............  ..............
NO2.............................               1  ..............  ..............  ..............  ..............
CO..............................  ..............  ..............             500  ..............           2,000
----------------------------------------------------------------------------------------------------------------

    (d) Significance determinations.
    (1) The projected emissions of any air pollutant other than VOC 
from any facility which result in an onshore ambient air concentration 
above the significance levels determined under paragraph (c) of this 
section for that air pollutant shall be deemed to significantly affect 
the air quality of the onshore area for that air pollutant.
    (2) The projected emissions of VOC from any facility which is not 
exempt under paragraph (b) of this section for that air pollutant shall 
be deemed to significantly affect the air quality of the onshore area 
for VOC.
    (e) Controls required. (1) The projected emissions of any air 
pollutant which significantly affect the air quality of an onshore area 
shall be reduced through the application of BACT.
    (2) The lessee shall submit a compliance schedule for the 
application of BACT. If it is necessary to cease operations to allow 
for the installation of emission controls, the lessee may apply for a 
suspension of operations under the provisions of 30 CFR 250.174.
    (f) Review of facilities with emissions below the exemption amount. 
If, during the review of the information required under paragraph 
(a)(6) of this section, the Regional Supervisor determines or an 
affected State submits information to the Regional Supervisor which 
demonstrates, in the judgment of the Regional Supervisor, that 
projected emissions from an otherwise exempt facility will, either 
individually or in combination with other facilities in the area, 
significantly affect the air quality of an onshore area, then the 
Regional Supervisor shall require the lessee to submit additional 
information to determine whether control measures are necessary. The 
lessee shall be given the opportunity to present information to the 
Regional Supervisor which demonstrates that the exempt facility is not 
significantly affecting the air quality of an onshore area of the 
State.
    (g) Emission monitoring requirements. The lessee shall monitor, in 
a manner approved or prescribed by the Regional

[[Page 64658]]

Supervisor, emissions from the facility following the installation of 
emission controls. The lessee shall submit this information monthly in 
a manner and form approved or prescribed by the Regional Supervisor.
    (h) Collection of meteorological data. The Regional Supervisor may 
require the lessee to collect, for a period of time and in a manner 
approved or prescribed by the Regional Supervisor, and submit 
meteorological data from a facility.

Subpart D--[Reserved]

Subpart E--[Reserved]

Subpart F--[Reserved]

Subpart G--[Reserved]

Subpart H--[Reserved]

Subpart I--[Reserved]

Subpart J--Pipelines and Pipeline Rights-of-Way

Sec.  550.1011  Bond requirements for pipeline right-of-way holders.

    (a) When you apply for, or are the holder of, a right-of-way, you 
must:
    (1) Provide and maintain a $300,000 bond (in addition to the bond 
coverage required in 30 CFR part 256 and 30 CFR part 556) that 
guarantees compliance with all the terms and conditions of the rights-
of-way you hold in an OCS area; and
    (2) Provide additional security if the Regional Director determines 
that a bond in excess of $300,000 is needed.
    (b) For the purpose of this paragraph, there are three areas:
    (1) The Gulf of Mexico and the area offshore the Atlantic Coast;
    (2) The areas offshore the Pacific Coast States of California, 
Oregon, Washington, and Hawaii; and
    (3) The area offshore the Coast of Alaska.
    (c) If, as the result of a default, the surety on a right-of-way 
grant bond makes payment to the Government of any indebtedness under a 
grant secured by the bond, the face amount of such bond and the 
surety's liability shall be reduced by the amount of such payment.
    (d) After a default, a new bond in the amount of $300,000 shall be 
posted within 6 months or such shorter period as the Regional 
Supervisor may direct. Failure to post a new bond shall be grounds for 
forfeiture of all grants covered by the defaulted bond.

Subpart K--Oil and Gas Production Requirements.

Well Tests and Surveys

Sec.  550.1153  When must I conduct a static bottomhole pressure 
survey?

    (a) You must conduct a static bottomhole pressure survey under the 
following conditions:

 
----------------------------------------------------------------------------------------------------------------
                  If you have . . .                                   Then you must conduct . . .
----------------------------------------------------------------------------------------------------------------
(1) A new producing reservoir,                        A static bottomhole pressure survey within 90 days after
                                                       the date of first continuous production.
(2) A reservoir with three or more producing          Annual static bottomhole pressure surveys in a sufficient
 completions,                                          number of key wells to establish an average reservoir
                                                       pressure. The Regional Supervisor may require that
                                                       bottomhole pressure surveys be performed on specific
                                                       wells.
----------------------------------------------------------------------------------------------------------------

     (b) Your bottomhole pressure survey must meet the following 
requirements:
    (1) You must shut-in the well for a minimum period of 4 hours to 
ensure stabilized conditions; and
    (2) The bottomhole pressure survey must consist of a pressure 
measurement at mid-perforation, and pressure measurements and gradient 
information for at least four gradient stops coming out of the hole.
    (c) You must submit to the Regional Supervisor the results of all 
static bottomhole pressure surveys on Form BOEM-140, Bottomhole 
Pressure Survey Report, within 60 days after the date of the survey.
    (d) The Regional Supervisor may grant a departure from the 
requirement to run a static bottomhole pressure survey. To request a 
departure, you must submit a justification, along with Form BOEM-140, 
Bottomhole Pressure Survey Report, showing a calculated bottomhole 
pressure or any measured data.

Classifying Reservoirs

Sec.  550.1154  How do I determine if my reservoir is sensitive?

    (a) You must determine whether each reservoir is sensitive. You 
must classify the reservoir as sensitive if:
    (1) Under initial conditions it is an oil reservoir with an 
associated gas cap;
    (2) At any time there are near-critical fluids; or
    (3) The reservoir is undergoing enhanced recovery.
    (b) For the purposes of this subpart, near-critical fluids are:
    (1) Those fluids that occur in high temperature, high-pressure 
reservoirs where it is not possible to define the liquid-gas contact; 
or
    (2) Fluids in reservoirs that are near bubble point or dew point 
conditions.
    (c) The Regional Supervisor may reclassify a reservoir when 
available information warrants reclassification.
    (d) If available information indicates that a reservoir previously 
classified as non-sensitive is now sensitive, you must submit a request 
to the Regional Supervisor to reclassify the reservoir. You must 
include supporting information, as listed in the table in Sec.  
550.1167, with your request.
    (e) If information indicates that a reservoir previously classified 
as sensitive is now non-sensitive, you may submit a request to the 
Regional Supervisor to reclassify the reservoir. You must include 
supporting information, as listed in the table in Sec.  550.1167, with 
your request.

Sec.  550.1155  What information must I submit for sensitive 
reservoirs?

    You must submit to the Regional Supervisor an original and two 
copies of Form BOEM-0127; one of the copies must be a public 
information copy in accordance with Sec. Sec.  550.186 and 550.197, and 
marked ``Public Information.'' You must also submit two copies of the 
supporting information, as listed in the table in Sec.  550.1167. You 
must submit this information:

[[Page 64659]]

    (a) Within 45 days after beginning production from the reservoir or 
discovering that it is sensitive;
    (b) At least once during the calendar year, but you do not need to 
resubmit unrevised structure maps (Sec.  550.1167(a)(2)) or previously 
submitted well logs (Sec.  550.1167(c)(1));
    (c) Within 45 days after you revise reservoir parameters; and
    (d) Within 45 days after the Regional Supervisor classifies the 
reservoir as sensitive under Sec.  550.1154(c).

Other Requirements

Sec.  550.1165  What must I do for enhanced recovery operations?

    (a) [Reserved]
    (b) Before initiating enhanced recovery operations, you must submit 
a proposed plan to the BSEE Regional Supervisor and receive approval 
for pressure maintenance, secondary or tertiary recovery, cycling, and 
similar recovery operations intended to increase the ultimate recovery 
of oil and gas from a reservoir. The proposed plan must include, for 
each project reservoir, a geologic and engineering overview, Form BOEM-
0127 (submitted to BOEM) and supporting data as required in Sec.  
550.1167, 30 CFR 250.1167, and any additional information required by 
the BSEE Regional Supervisor.
    (c) [Reserved].

Sec.  550.1166  What additional reporting is required for developments 
in the Alaska OCS Region?

    (a) [Reserved]
    (b) [Reserved]
    (c) Every time you are required to submit Form BOEM-0127 under 
Sec.  550.1155, you must request an MER for each producing sensitive 
reservoir in the Alaska OCS Region, unless otherwise instructed by the 
Regional Supervisor.

Sec.  550.1167  What information must I submit with forms and for 
approvals?

    You must submit the supporting information listed in the following 
table with the form identified in column 1 and for the approval 
required under this subpart identified in column 2:

 
----------------------------------------------------------------------------------------------------------------
                                                                  SRI BOEM-0127  (2             Reservoir
                                                                       copies)              reclassification
----------------------------------------------------------------------------------------------------------------
(a) Maps:                                                     ........................  ........................
    (1) Base map with surface, bottomhole, and completion     ........................  ........................
     locations with respect to the unit or lease line and
     the orientation of representative seismic lines or
     cross-sections.........................................
    (2) Structure maps with penetration point and subsea                      [radic]                   [radic]
     depth for each well penetrating the reservoirs,
     highlighting subject wells; reservoir boundaries; and
     original and current fluid levels......................
    (3) Net sand isopach with total net sand penetrated for                         *   ........................
     each well, identified at the penetration point.........
    (4) Net hydrocarbon isopach with net feet of pay for                            *   ........................
     each well, identified at the penetration point.........
(b) Seismic data:                                             ........................  ........................
    (1) Representative seismic lines, including strike and    ........................  ........................
     dip lines that confirm the structure; indicate polarity
    (2) Amplitude extraction of seismic horizon, if           ........................                  [radic]
     applicable.............................................
(c) Logs:                                                     ........................  ........................
    (1) Well log sections with tops and bottoms of the                        [radic]                   [radic]
     reservoir(s) and proposed or existing perforations.....
    (2) Structural cross-sections showing the subject well    ........................                  [radic]
     and nearby wells.......................................
(d) Engineering data:                                         ........................  ........................
    (1) Estimated recoverable reserves for each well                          [radic]   ........................
     completion in the reservoir; total recoverable reserves
     for each reservoir; method of calculation; reservoir
     parameters used in volumetric and decline curve
     analysis...............................................
    (2) Well schematics showing current and proposed          ........................  ........................
     conditions.............................................
    (3) The drive mechanism of each reservoir...............                  [radic]                   [radic]
    (4) Pressure data, by date, and whether they are          ........................                  [radic]
     estimated or measured..................................
    (5) Production data and decline curve analysis            ........................                  [radic]
     indicative of the reservoir performance................
    (6) Reservoir simulation with the reservoir parameters    ........................                        *
     used, history matches, and prediction runs (include
     proposed development scenario).........................
(e) General information:                                      ........................  ........................
    (1) Detailed economic analysis..........................  ........................  ........................
    (2) Reservoir name and whether or not it is competitive                   [radic]                   [radic]
     as defined under Sec.   250.105........................
    (3) Operator name, lessee name(s), block, lease number,   ........................  ........................
     royalty rate, and unit number (if applicable) of all
     relevant leases........................................
    (4) Geologic overview of project........................  ........................                  [radic]
    (5) Explanation of why the proposed completion scenario   ........................  ........................
     will maximize ultimate recovery........................
    (6) List of all wells in subject reservoirs that have     ........................                  [radic]
     ever produced or been used for injection...............
----------------------------------------------------------------------------------------------------------------
[radic] Required.
* Additional items the Regional Supervisor may request.
Note: All maps must be at a standard scale and show lease and unit lines. The Regional Supervisor may waive
  submittal of some of the required data on a case-by-case basis.

    (f) Depending on the type of approval requested, you must submit 
the appropriate payment of the service fee(s) listed in Sec.  550.125, 
according to the instructions in Sec.  550.126.

[[Page 64660]]

Subpart L--[Reserved]

Subpart M--[Reserved]

Subpart N--Outer Continental Shelf Civil Penalties

Outer Continental Shelf Lands Act Civil Penalties

Sec.  550.1400  How does BOEM begin the civil penalty process?

    This subpart explains BOEM's civil penalty procedures whenever a 
lessee, operator or other person engaged in oil, gas, sulphur or other 
minerals operations in the OCS has a violation. Whenever BOEM 
determines, on the basis of available evidence, that a violation 
occurred and a civil penalty review is appropriate, it will prepare a 
case file. BOEM will appoint a Reviewing Officer.

Sec.  550.1401  Index table.

    The following table is an index of the sections in this subpart:

------------------------------------------------------------------------
 
------------------------------------------------------------------------
(a) Definitions.........................  Sec.   550.1402
(b) What is the maximum civil penalty?..  Sec.   550.1403
(c) Which violations will BOEM review     Sec.   550.1404
 for potential civil penalties?.
(d) When is a case file developed?......  Sec.   550.1405
(e) When will BOEM notify me and provide  Sec.   550.1406
 penalty information?.
(f) How do I respond to the letter of     Sec.   550.1407
 notification?.
(g) When will I be notified of the        Sec.   550.1408
 Reviewing Officer's decision?.
(h) What are my appeal rights?..........  Sec.   550.1409
------------------------------------------------------------------------

Sec.  550.1402  Definitions.

    Terms used in this subpart have the following meaning:
    Case file means a BOEM document file containing information and the 
record of evidence related to the alleged violation.
    Civil penalty means a fine. It is a BOEM regulatory enforcement 
tool used in addition to Notices of Incidents of Noncompliance and 
directed suspensions of production or other operations.
    Reviewing Officer means a BOEM employee assigned to review case 
files and assess civil penalties.
    Violation means failure to comply with the Outer Continental Shelf 
Lands Act (OCSLA) or any other applicable laws, with any regulations 
issued under the OCSLA, or with the terms or provisions of leases, 
licenses, permits, rights-of-way, or other approvals issued under the 
OCSLA.
    Violator means a person responsible for a violation.

Sec.  550.1403  What is the maximum civil penalty?

    The maximum civil penalty is $40,000 per day per violation.

Sec.  550.1404  Which violations will BOEM review for potential civil 
penalties?

    BOEM will review each of the following violations for potential 
civil penalties:
    (a) Violations that you do not correct within the period BOEM 
grants;
    (b) [Reserved]
    (c) [Reserved]
    (d) Violations of the oil spill financial responsibility 
requirements at 30 CFR part 553.

Sec.  550.1405  When is a case file developed?

    BOEM will develop a case file during its investigation of the 
violation, and forward it to a Reviewing Officer if any of the 
conditions in Sec.  550.1404 exist. The Reviewing Officer will review 
the case file and determine if a civil penalty is appropriate. The 
Reviewing Officer may administer oaths and issue subpoenas requiring 
witnesses to attend meetings, submit depositions, or produce evidence.

Sec.  550.1406  When will BOEM notify me and provide penalty 
information?

    If the Reviewing Officer determines that a civil penalty should be 
assessed, the Reviewing Officer will send the violator a letter of 
notification. The letter of notification will include:
    (a) The amount of the proposed civil penalty;
    (b) Information on the violation(s); and
    (c) Instruction on how to obtain a copy of the case file, schedule 
a meeting, submit information, or pay the penalty.

Sec.  550.1407  How do I respond to the letter of notification?

    You have 30 calendar days after you receive the Reviewing Officer's 
letter to either:
    (a) Request, in writing, a meeting with the Reviewing Officer;
    (b) Submit additional information; or
    (c) Pay the proposed civil penalty.

Sec.  550.1408  When will I be notified of the Reviewing Officer's 
decision?

    At the end of the 30 calendar days or after the meeting and 
submittal of additional information, the Reviewing Officer will review 
the case file, including all information you submitted, and send you a 
decision. The decision will include the amount of any final civil 
penalty, the basis for the civil penalty, and instructions for paying 
or appealing the civil penalty.

Sec.  550.1409  What are my appeal rights?

    (a) When you receive the Reviewing Officer's final decision, you 
have 60 days to either pay the penalty or file an appeal in accordance 
with 30 CFR part 590, subpart A.
    (b) If you file an appeal, you must either:
    (1) Submit a surety bond in the amount of the penalty to the 
appropriate Leasing Office in the Region where the penalty was 
assessed, following instructions that the Reviewing Officer will 
include in the final decision; or
    (2) Notify the appropriate Leasing Office, in the Region where the 
penalty was assessed, that you want your lease-specific/area-wide bond 
on file to be used as the bond for the penalty amount.
    (c) If you choose the alternative in paragraph (b)(2) of this 
section, the BOEM Regional Director may require additional security 
(i.e., security in excess of your existing bond) to ensure sufficient 
coverage during an appeal. In that event, the Regional Director will 
require you to post the supplemental bond with the regional office in 
the same manner as under Sec.  556.53(d) through (f) of this chapter. 
If the Regional Director determines the appeal should be covered by a 
lease-specific abandonment account then you must establish an account 
that meets the requirements of Sec.  556.56.
    (d) If you do not either pay the penalty or file a timely appeal, 
BOEM

[[Page 64661]]

will take one or more of the following actions:
    (1) We will collect the amount you were assessed, plus interest, 
late payment charges, and other fees as provided by law, from the date 
you received the Reviewing Officer's final decision until the date we 
receive payment;
    (2) We may initiate additional enforcement, including, if 
appropriate, cancellation of the lease, right-of-way, license, permit, 
or approval, or the forfeiture of a bond under this part; or
    (3) We may bar you from doing further business with the Federal 
Government according to Executive Orders 12549 and 12689, and section 
2455 of the Federal Acquisition Streamlining Act of 1994, 31 U.S.C. 
6101. The Department of the Interior's regulations implementing these 
authorities are found at 43 CFR part 12, subpart D.

Federal Oil and Gas Royalty Management Act Civil Penalties Definitions

Sec.  550.1450  What definitions apply to this subpart?

    The terms used in this subpart have the same meaning as in 30 
U.S.C. 1702.

Penalties After a Period to Correct

Sec.  550.1451  What may BOEM do if I violate a statute, regulation, 
order, or lease term relating to a Federal oil and gas lease?

    (a) If we believe that you have not followed any requirement of a 
statute, regulation, order, or lease term for any Federal oil or gas 
lease, we may send you a Notice of Noncompliance informing you what the 
violation is and what you need to do to correct it to avoid civil 
penalties under 30 U.S.C. 1719(a) and (b).
    (b) We will serve the Notice of Noncompliance by registered mail or 
personal service using the most current address on file as maintained 
by the BOEM Leasing Office in your respective Region.

Sec.  550.1452  What if I correct the violation?

    The matter will be closed if you correct all of the violations 
identified in the Notice of Noncompliance within 20 days after you 
receive the Notice (or within a longer time period specified in the 
Notice).

Sec.  550.1453  What if I do not correct the violation?

    (a) We may send you a Notice of Civil Penalty if you do not correct 
all of the violations identified in the Notice of Noncompliance within 
20 days after you receive the Notice of Noncompliance (or within a 
longer time period specified in that Notice). The Notice of Civil 
Penalty will tell you how much penalty you must pay. The penalty may be 
up to $500 per day, beginning with the date of the Notice of 
Noncompliance, for each violation identified in the Notice of 
Noncompliance for as long as you do not correct the violations.
    (b) If you do not correct all of the violations identified in the 
Notice of Noncompliance within 40 days after you receive the Notice of 
Noncompliance (or 20 days following the expiration of a longer time 
period specified in that Notice), we may increase the penalty to up to 
$5,000 per day, beginning with the date of the Notice of Noncompliance, 
for each violation for as long as you do not correct the violations.

Sec.  550.1454  How may I request a hearing on the record on a Notice 
of Noncompliance?

    You may request a hearing on the record on a Notice of 
Noncompliance by filing a request within 30 days of the date you 
received the Notice of Noncompliance with the Hearings Division 
(Departmental), Office of Hearings and Appeals, U.S. Department of the 
Interior, 801 North Quincy Street, Arlington, Virginia 22203. You may 
do this regardless of whether you correct the violations identified in 
the Notice of Noncompliance.

Sec.  550.1455  Does my request for a hearing on the record affect the 
penalties?

    (a) If you do not correct the violations identified in the Notice 
of Noncompliance, the penalties will continue to accrue even if you 
request a hearing on the record.
    (b) You may petition the Hearings Division (Departmental) of the 
Office of Hearings and Appeals, to stay the accrual of penalties 
pending the hearing on the record and a decision by the Administrative 
Law Judge under Sec.  550.1472.
    (1) You must file your petition within 45 calendar days of 
receiving the Notice of Noncompliance.
    (2) To stay the accrual of penalties, you must post a bond or other 
surety instrument, or demonstrate financial solvency, using the 
standards and requirements as prescribed in Sec. Sec.  550.1490 through 
550.1497, for the principal amount of any unpaid amounts due that are 
the subject of the Notice of Noncompliance, including interest thereon, 
plus the amount of any penalties accrued before the date a stay becomes 
effective.
    (3) The Hearings Division will grant or deny the petition under 43 
CFR 4.21(b).

Sec.  550.1456  May I request a hearing on the record regarding the 
amount of a civil penalty if I did not request a hearing on the Notice 
of Noncompliance?

    (a) You may request a hearing on the record to challenge only the 
amount of a civil penalty when you receive a Notice of Civil Penalty, 
if you did not previously request a hearing on the record under Sec.  
550.1454. If you did not request a hearing on the record on the Notice 
of Noncompliance under Sec.  550.1454, you may not contest your 
underlying liability for civil penalties.
    (b) You must file your request within 10 days after you receive the 
Notice of Civil Penalty with the Hearings Division (Departmental), 
Office of Hearings and Appeals, U.S. Department of the Interior, 801 
North Quincy Street, Arlington, Virginia 22203.

Penalties Without a Period to Correct

Sec.  550.1460  May I be subject to penalties without prior notice and 
an opportunity to correct?

    The Federal Oil and Gas Royalty Management Act sets out several 
specific violations for which penalties accrue without an opportunity 
to first correct the violation.
    (a) [Reserved]
    (b) Under 30 U.S.C. 1719(d), you may be subject to civil penalties 
of up to $25,000 per day for each day each violation continues if you:
    (1) Knowingly or willfully prepare, maintain, or submit false, 
inaccurate, or misleading reports, notices, affidavits, records, data, 
or other written information;
    (2) [Reserved]
    (3) [Reserved]

Sec.  550.1461  How will BOEM inform me of violations without a period 
to correct?

    We will inform you of any violation, without a period to correct, 
by issuing a Notice of Noncompliance and Civil Penalty explaining the 
violation, how to correct it, and the penalty assessment. We will serve 
the Notice of Noncompliance and Civil Penalty by registered mail or 
personal service using your address of record as specified under 30 CFR 
part 1218, subpart H.

Sec.  550.1462  How may I request a hearing on the record on a Notice 
of Noncompliance regarding violations without a period to correct?

    You may request a hearing on the record of a Notice of 
Noncompliance regarding violations without a period to correct by 
filing a request within 30 days after you receive the Notice of 
Noncompliance with the Hearings Division (Departmental), Office of 
Hearings and Appeals, U.S. Department of the Interior, 801 North Quincy 
Street,

[[Page 64662]]

Arlington, Virginia 22203. You may do this regardless of whether you 
correct the violations identified in the Notice of Noncompliance.

Sec.  550.1463  Does my request for a hearing on the record affect the 
penalties?

    (a) If you do not correct the violations identified in the Notice 
of Noncompliance regarding violations without a period to correct, the 
penalties will continue to accrue even if you request a hearing on the 
record.
    (b) You may ask the Hearings Division (Departmental) to stay the 
accrual of penalties pending the hearing on the record and a decision 
by the Administrative Law Judge under Sec.  550.1472.
    (1) You must file your petition within 45 calendar days after you 
receive the Notice of Noncompliance.
    (2) To stay the accrual of penalties, you must post a bond or other 
surety instrument, or demonstrate financial solvency, using the 
standards and requirements as prescribed in Sec. Sec.  550.1490 through 
550.1497, for the principal amount of any unpaid amounts due that are 
the subject of the Notice of Noncompliance, including interest thereon, 
plus the amount of any penalties accrued before the date a stay becomes 
effective.
    (3) The Hearings Division will grant or deny the petition under 43 
CFR 4.21(b).

Sec.  550.1464  May I request a hearing on the record regarding the 
amount of a civil penalty if I did not request a hearing on the Notice 
of Noncompliance?

    (a) You may request a hearing on the record to challenge only the 
amount of a civil penalty when you receive a Notice of Civil Penalty 
regarding violations without a period to correct, if you did not 
previously request a hearing on the record under Sec.  550.1462. If you 
did not request a hearing on the record on the Notice of Noncompliance 
under Sec.  550.1462, you may not contest your underlying liability for 
civil penalties.
    (b) You must file your request within 10 days after you receive 
Notice of Civil Penalty with the Hearings Division (Departmental), 
Office of Hearings and Appeals, U.S. Department of the Interior, 801 
North Quincy, Arlington, Virginia 22203.

General Provisions

Sec.  550.1470  How does BOEM decide what the amount of the penalty 
should be?

    We determine the amount of the penalty by considering the severity 
of the violations, your history of compliance, and if you are a small 
business.

Sec.  550.1471  Does the penalty affect whether I owe interest?

    If you do not pay the penalty by the date required under Sec.  
550.1475(d), BOEM will assess you late payment interest on the penalty 
amount at the same rate interest is assessed under 30 CFR 1218.54.

Sec.  550.1472  How will the Office of Hearings and Appeals conduct the 
hearing on the record?

    If you request a hearing on the record under Sec. Sec.  550.1454, 
550.1456, 550.1462, or 550.1464, the hearing will be conducted by a 
Departmental Administrative Law Judge from the Office of Hearings and 
Appeals. After the hearing, the Administrative Law Judge will issue a 
decision in accordance with the evidence presented and applicable law.

Sec.  550.1473  How may I appeal the Administrative Law Judge's 
decision?

    If you are adversely affected by the Administrative Law Judge's 
decision, you may appeal that decision to the Interior Board of Land 
Appeals under 43 CFR part 4, subpart E.

Sec.  550.1474  May I seek judicial review of the decision of the 
Interior Board of Land Appeals?

    Under 30 U.S.C. 1719(j), you may seek judicial review of the 
decision of the Interior Board of Land Appeals. A suit for judicial 
review in the District Court will be barred unless filed within 90 days 
after the final order.

Sec.  550.1475  When must I pay the penalty?

    (a) You must pay the amount of the Notice of Civil Penalty issued 
under Sec. Sec.  550.1453 or 550.1461, if you do not request a hearing 
on the record under Sec. Sec.  550.1454, 550.1456, 550.1462, or 
550.1464
    (b) If you request a hearing on the record under Sec. Sec.  
550.1454, 550.1456, 550.1462, or 550.1464, but you do not appeal the 
determination of the Administrative Law Judge to the Interior Board of 
Land Appeals under Sec.  550.1473, you must pay the amount assessed by 
the Administrative Law Judge.
    (c) If you appeal the determination of the Administrative Law Judge 
to the Interior Board of Land Appeals, you must pay the amount assessed 
in the IBLA decision.
    (d) You must pay the penalty assessed within 40 days after:
    (1) You received the Notice of Civil Penalty, if you did not 
request a hearing on the record under either Sec. Sec.  550.1454, 
550.1456, 550.1462, or 550.1464;
    (2) You received an Administrative Law Judge's decision under Sec.  
550.1472, if you obtained a stay of the accrual of penalties pending 
the hearing on the record under Sec.  550.1455(b) or Sec.  550.1463(b) 
and did not appeal the Administrative Law Judge's determination to the 
IBLA under Sec.  550.1473;
    (3) You received an IBLA decision under Sec.  550.1473 if the IBLA 
continued the stay of accrual of penalties pending its decision and you 
did not seek judicial review of the IBLA's decision; or
    (4) A final non-appealable judgment of a court of competent 
jurisdiction is entered, if you sought judicial review of the IBLA's 
decision and the Department or the appropriate court suspended 
compliance with the IBLA's decision pending the adjudication of the 
case.
    (e) If you do not pay, that amount is subject to collection under 
the provisions of Sec.  550.1477.

Sec.  550.1476  Can BOEM reduce my penalty once it is assessed?

    Under 30 U.S.C. 1719(g), the Director or his or her delegate may 
compromise or reduce civil penalties assessed under this part.

Sec.  550.1477  How may BOEM collect the penalty?

    (a) BOEM may use all available means to collect the penalty 
including, but not limited to:
    (1) Requiring the lease surety, for amounts owed by lessees, to pay 
the penalty;
    (2) Deducting the amount of the penalty from any sums the United 
States owes to you; and
    (3) Using judicial process to compel your payment under 30 U.S.C. 
1719(k).
    (b) If the Department uses judicial process, or if you seek 
judicial review under Sec.  550.1474 and the court upholds assessment 
of a penalty, the court shall have jurisdiction to award the amount 
assessed plus interest assessed from the date of the expiration of the 
90-day period referred to in Sec.  550.1474. The amount of any penalty, 
as finally determined, may be deducted from any sum owing to you by the 
United States.

Criminal Penalties

Sec.  550.1480  May the United States criminally prosecute me for 
violations under Federal oil and gas leases?

    If you commit an act for which a civil penalty is provided at 30 
U.S.C. 1719(d) and Sec.  550.1460(b), the United States may pursue 
criminal penalties as provided at 30 U.S.C. 1720, in addition to any 
authority for prosecution under other statutes.

[[Page 64663]]

Bonding Requirements

Sec.  550.1490  What standards must my BOEM-specified surety instrument 
meet?

    (a) A BOEM-specified surety instrument must be in a form specified 
in BOEM instructions. BOEM will give you written information and 
standard forms for BOEM-specified surety instrument requirements.
    (b) BOEM will use a bank-rating service to determine whether a 
financial institution has an acceptable rating to provide a surety 
instrument adequate to indemnify the lessor from loss or damage.
    (1) Administrative appeal bonds must be issued by a qualified 
surety company which the Department of the Treasury has approved.
    (2) Irrevocable letters of credit or certificates of deposit must 
be from a financial institution acceptable to BOEM with a minimum 1-
year period of coverage subject to automatic renewal up to 5 years.

Sec.  550.1491  How will BOEM determine the amount of my bond or other 
surety instrument?

    (a) BOEM bond-approving officer may approve your surety if he or 
she determines that the amount is adequate to guarantee payment. The 
amount of your surety may vary depending on the form of the surety and 
how long the surety is effective.
    (1) The amount of the BOEM-specified surety instrument must include 
the principal amount owed under the Notice of Noncompliance or Notice 
of Civil Penalty plus any accrued interest we determine is owed plus 
projected interest for a 1-year period.
    (2) Treasury book-entry bond or note amounts must be equal to at 
least 120 percent of the required surety amount.
    (b) If your appeal is not decided within 1 year from the filing 
date, you must increase the surety amount to cover additional estimated 
interest for another 1-year period. You must continue to do this 
annually on the date your appeal was filed. We will determine the 
additional estimated interest and notify you of the amount so you can 
amend your surety instrument.
    (c) You may submit a single surety instrument that covers multiple 
appeals. You may change the instrument to add new amounts under appeal 
or remove amounts that have been adjudicated in your favor or that you 
have paid, if you:
    (1) Amend the single surety instrument annually on the date you 
filed your first appeal; and
    (2) Submit a separate surety instrument for new amounts under 
appeal until you amend the instrument to cover the new appeals.

Financial Solvency Requirements

Sec.  550.1495  How do I demonstrate financial solvency?

    (a) To demonstrate financial solvency under this part, you must 
submit an audited consolidated balance sheet, and, if requested by the 
BOEM bond-approving officer, up to 3 years of tax returns to BOEM using 
the U.S. Postal Service, private delivery, courier, or overnight 
delivery at:
    (1) For Alaska OCS: Jeffrey Walker, RS/FO, BOEM Alaska OCS Region, 
3801 Centerpoint Drive, Suite 500, Anchorage, AK 99503-5823, 
jeffrey.walker@boem.gov, (907) 334-5300.
    (2) For Gulf of Mexico and Atlantic OCS: Joshua Joyce, Regional 
FARM Program Coordinator, BOEM Gulf of Mexico OCS Region, 1201 Elmwood 
Park Boulevard New Orleans, LA 70123-2394, joshua.joyce@boem.gov, (504) 
736-2779.
    (3) For Pacific OCS: Jaron Ming, Lead Leasing Specialist, BOEM 
Pacific OCS Region, 770 Paseo Camarillo, 2nd Floor, Camarillo, CA 
93010, jaron.ming@boem.gov, (805) 389-7514.
    (b) You must submit an audited consolidated balance sheet annually, 
and, if requested, additional annual tax returns on the date BOEM first 
determined that you demonstrated financial solvency as long as you have 
active appeals, or whenever BOEM requests.
    (c) If you demonstrate financial solvency in the current calendar 
year, you are not required to redemonstrate financial solvency for new 
appeals of orders during that calendar year unless you file for 
protection under any provision of the U.S. Bankruptcy Code (Title 11 of 
the United States Code), or BOEM notifies you that you must 
redemonstrate financial solvency.

Sec.  550.1496  How will BOEM determine if I am financially solvent?

    (a) BOEM bond-approving officer will determine your financial 
solvency by examining your total net worth, including, as appropriate, 
the net worth of your affiliated entities.
    (b) If your net worth, minus the amount we would require as surety 
under Sec. Sec.  550.1490 and 550.1491 for all orders you have appealed 
is greater than $300 million, you are presumptively deemed financially 
solvent, and we will not require you to post a bond or other surety 
instrument.
    (c) If your net worth, minus the amount we would require as surety 
under Sec. Sec.  550.1490 and 550.1491 for all orders you have appealed 
is less than $300 million, you must submit the following to BOEM by one 
of the methods in Sec. Sec.  550.1495(a):
    (1) A written request asking us to consult a business-information, 
or credit-reporting service or program to determine your financial 
solvency; and
    (2) A nonrefundable $50 processing fee:
    (i) You must pay the processing fee to us following the 
requirements for making payments found in 30 CFR 550.126. You are 
required to use Electronic Funds Transfer (EFT) for these payments;
    (ii) You must submit the fee with your request under paragraph 
(c)(1) of this section, and then annually on the date we first 
determined that you demonstrated financial solvency, as long as you are 
not able to demonstrate financial solvency under paragraph (a) of this 
section and you have active appeals.
    (d) If you request that we consult a business-information or 
credit-reporting service or program under paragraph (c) of this 
section:
    (1) We will use criteria similar to that which a potential creditor 
would use to lend an amount equal to the bond or other surety 
instrument we would require under Sec. Sec.  550.1490 and 550.1491;
    (2) For us to consider you financially solvent, the business-
information or credit-reporting service or program must demonstrate 
your degree of risk as low to moderate:
    (i) If our bond-approving officer determines that the business-
information or credit-reporting service or program information 
demonstrates your financial solvency to our satisfaction, our bond-
approving officer will not require you to post a bond or other surety 
instrument under Sec. Sec.  550.1490 and 550.1491;
    (ii) If our bond-approving officer determines that the business-
information or credit-reporting service or program information does not 
demonstrate your financial solvency to our satisfaction, our bond-
approving officer will require you to post a bond or other surety 
instrument under Sec. Sec.  550.1490 and 550.1491 or pay the 
obligation.

Sec.  550.1497  When will BOEM monitor my financial solvency?

    (a) If you are presumptively financially solvent under Sec.  
550.1496(b), BOEM will determine your net worth as described under 
Sec. Sec.  550.1496(b) and (c) to evaluate your financial solvency at 
least annually on the date we first determined that you demonstrated 
financial solvency as long as you have

[[Page 64664]]

active appeals and each time you appeal a new order.
    (b) If you ask us to consult a business-information or credit-
reporting service or program under Sec.  550.1496(c), we will consult a 
service or program annually as long as you have active appeals and each 
time you appeal a new order.
    (c) If our bond-approving officer determines that you are no longer 
financially solvent, you must post a bond or other BOEM-specified 
surety instrument under Sec. Sec.  550.1490 and 550.1491.

Subpart O--[Reserved]

Subpart P--[Reserved]

Subpart Q--[Reserved]

Subpart R--[Reserved]

Subpart S--[Reserved]

PART 551--GEOLOGICAL AND GEOPHYSCIAL (G&G) EXPLORATIONS OF THE 
OUTER CONTINENTAL SHELF

Sec.
551.1 Definitions.
551.2 Purpose of this part.
551.3 Authority and applicability of this part.
551.4 Types of G&G activities that require permits or Notices.
551.5 Applying for permits or filing Notices.
551.6 Obligations and rights under a permit or a Notice.
551.7 Test drilling activities under a permit.
551.8 Inspection and reporting requirements for activities under a 
permit.
551.9 Temporarily stopping, canceling, or relinquishing activities 
approved under a permit.
551.10 Penalties and appeals.
551.11 Submission, inspection, and selection of geological data and 
information collected under a permit and processed by permittees or 
third parties.
551.12 Submission, inspection, and selection of geophysical data and 
information collected under a permit and processed by permittees or 
third parties.
551.13 Reimbursement for the costs of reproducing data and 
information and certain processing costs.
551.14 Protecting and disclosing data and information submitted to 
BOEM under a permit.
551.15 Authority for information collection.

    Authority: 31 U.S.C. 9701, 43 U.S.C. 1334.

Sec.  551.1  Definitions.

    Terms used in this part have the following meaning:
    Act means the Outer Continental Shelf Lands Act (OCSLA), as amended 
(43 U.S.C. 1331 et seq.).
    Analyzed geological information means data collected under a permit 
or a lease that have been analyzed. Analysis may include, but is not 
limited to, identification of lithologic and fossil content, core 
analyses, laboratory analyses of physical and chemical properties, well 
logs or charts, results from formation fluid tests, and descriptions of 
hydrocarbon occurrences or hazardous conditions.
    Archaeological interest means capable of providing scientific or 
humanistic understanding of past human behavior, cultural adaptation, 
and related topics through the application of scientific or scholarly 
techniques, such as controlled observation, contextual measurements, 
controlled collection, analysis, interpretation, and explanation.
    Archaeological resources mean any material remains of human life or 
activities that are at least 50 years of age and of archaeological 
interest.
    Coastal environment means the physical, atmospheric, and biological 
components, conditions, and factors that interactively determine the 
productivity, state, condition, and quality of the terrestrial 
ecosystem from the shoreline inward to the boundaries of the coastal 
zone.
    Coastal Zone means the coastal waters (including the lands therein 
and thereunder) and the adjacent shorelands (including the waters 
therein and thereunder), strongly influenced by each other and in 
proximity to the shorelines of the several coastal States and extends 
seaward to the outer limit of the U.S. territorial sea.
    Coastal Zone Management Act means the Coastal Zone Management Act 
of 1972, as amended (16 U.S.C. 1451 et seq.).
    Data means facts, statistics, measurements, or samples that have 
not been analyzed, processed, or interpreted.
    Deep stratigraphic test means drilling that involves the 
penetration into the sea bottom of more than 500 feet (152 meters).
    Director means the Director of the Bureau of Ocean Energy 
Management, U.S. Department of the Interior, or a subordinate 
authorized to act on the Director's behalf.
    Exploration means the commercial search for oil, gas, and sulphur. 
Activities classified as exploration include, but are not limited to:
    (1) Geological and geophysical marine and airborne surveys where 
magnetic, gravity, seismic reflection, seismic refraction, gas 
sniffers, coring, or other systems are used to detect or imply the 
presence of oil, gas, or sulphur; and
    (2) Any drilling, whether on or off a geological structure.
    Geological and geophysical scientific research means any oil, gas, 
or sulphur related investigation conducted in the OCS for scientific 
and/or research purposes. Geological, geophysical, and geochemical data 
and information gathered and analyzed are made available to the public 
for inspection and reproduction at the earliest practicable time. The 
term does not include commercial geological or geophysical exploration 
or research.
    Geological exploration means exploration that uses geological and 
geochemical techniques (e.g., coring and test drilling, well logging, 
and bottom sampling) to produce data and information on oil, gas, and 
sulphur resources in support of possible exploration and development 
activities. The term does not include geological scientific research.
    Geological information means geological or geochemical data that 
have been analyzed, processed, or interpreted.
    Geophysical data means measurements that have not been processed or 
interpreted.
    Geophysical exploration means exploration that utilizes geophysical 
techniques (e.g., gravity, magnetic, electromagnetic, or seismic) to 
produce data and information on oil, gas, and sulphur resources in 
support of possible exploration and development activities. The term 
does not include geophysical scientific research.
    Geophysical information means geophysical data that have been 
processed or interpreted.
    Governor means the Governor of a State or the person or entity 
lawfully designated to exercise the powers granted to a Governor 
pursuant to the Act.
    Human environment means the physical, social, and economic 
components, conditions, and factors which interactively determine the 
state, condition, and quality of living conditions, employment, and 
health of those affected, directly or indirectly, by activities 
occurring on the OCS.
    Hydrocarbon occurrence means the direct or indirect detection 
during drilling operations of any liquid or gaseous hydrocarbons by 
examination of well cuttings, cores, gas detector readings, formation 
fluid tests, wireline logs, or by any other means. The term does not 
include background gas, minor accumulations of gas, or heavy oil 
residues on cuttings and cores.
    Interpreted geological information means knowledge, often in the 
form of schematic cross sections, 3-dimensional representations, and 
maps, developed by determining the geological

[[Page 64665]]

significance of geological data and analyzed and processed geologic 
information.
    Interpreted geophysical information means knowledge, often in the 
form of seismic cross sections, 3-dimensional representations, and 
maps, developed by determining the geological significance of 
geophysical data and processed geophysical information.
    Lease means an agreement which is issued under section 8 or 
maintained under section 6 of the Act and which authorizes exploration 
for, and development and production of, minerals or the area covered by 
that authorization, whichever is required by the context.
    Lessee means a person who has entered into, or is the BOEM approved 
assignee of, a lease with the United States to explore for, develop, 
and produce the leased minerals. The term ``lessee'' also includes an 
owner of operating rights.
    Marine environment means the physical, atmospheric, and biological 
components, conditions, and factors that interactively determine the 
quality of the marine ecosystem in the coastal zone and in the OCS.
    Material remains mean physical evidence of human habitation, 
occupation, use, or activity, including the site, location, or context 
in which such evidence is situated.
    Minerals mean oil, gas, sulphur, geopressured-geothermal and 
associated resources, and all other minerals which are authorized by an 
Act of Congress to be produced from public lands as defined in section 
103 of the Federal Land Policy and Management Act of 1976 (43 U.S.C. 
1702).
    Notice means a written statement of intent to conduct geological or 
geophysical scientific research related to oil, gas, and sulphur in the 
OCS other than under a permit.
    Oil, gas, and sulphur means oil, gas, sulphur, geopressured-
geothermal, and associated resources.
    Outer Continental Shelf (OCS) means all submerged lands lying 
seaward and outside the area of lands beneath navigable waters as 
defined in section 2 of the Submerged Lands Act (43 U.S.C. 1301), and 
of which the subsoil and seabed appertain to the United States and are 
subject to its jurisdiction and control.
    Permit means the contract or agreement, other than a lease, issued 
pursuant to this part, under which a person acquires the right to 
conduct on the OCS, in accordance with appropriate statutes, 
regulations, and stipulations:
    (1) Geological exploration for mineral resources;
    (2) Geophysical exploration for mineral resources;
    (3) Geological scientific research; or
    (4) Geophysical scientific research.
    Permittee means the person authorized by a permit issued pursuant 
to this part to conduct activities on the OCS.
    Person means a citizen or national of the United States; an alien 
lawfully admitted for permanent residence in the United States as 
defined in section 8 U.S.C. 1101(a)(20); a private, public, or 
municipal corporation organized under the laws of the United States or 
of any State or territory thereof; and associations of such citizens, 
nationals, resident aliens, or private, public, or municipal 
corporations, States, or political subdivisions of States or anyone 
operating in a manner provided for by treaty or other applicable 
international agreements. The term does not include Federal agencies.
    Processed geological or geophysical information means data 
collected under a permit and later processed or reprocessed. Processing 
involves changing the form of data so as to facilitate interpretation. 
Processing operations may include, but are not limited to, applying 
corrections for known perturbing causes, rearranging or filtering data, 
and combining or transforming data elements. Reprocessing is the 
additional processing other than ordinary processing used in the 
general course of evaluation. Reprocessing operations may include 
varying identified parameters for the detailed study of a specific 
problem area. Reprocessing may occur several years after the original 
processing date. Reprocessing is determined to be completed on the date 
that the reprocessed information is first available in a useable format 
for in-house interpretation by BOEM or the permittee, or becomes first 
available to third parties via sale, trade, license agreement, or other 
means.
    Secretary means the Secretary of the Interior or a subordinate 
authorized to act on the Secretary's behalf.
    Shallow test drilling means drilling into the sea bottom to depths 
less than those specified in the definition of a deep stratigraphic 
test.
    Significant archaeological resource means those archaeological 
resources that meet the criteria of significance for eligibility to the 
National Register of Historic Places as defined in 36 CFR 60.4.
    Third Party means any person other than the permittee or a 
representative of the United States, including all persons who obtain 
data or information acquired under a permit from the permittee, or from 
another third party, by sale, trade, license agreement, or other means.
    Violation means a failure to comply with any provision of the Act, 
or a provision of a regulation or order issued under the Act, or any 
provision of a lease, license, or permit issued under the Act.
    You means a person who applies for and/or obtains a permit, or 
files a Notice to conduct geological or geophysical exploration or 
scientific research related to oil, gas, and sulphur in the OCS.

Sec.  551.2  Purpose of this part.

    (a) To allow you to conduct G&G activities in the OCS related to 
oil, gas, and sulphur on unleased lands or on lands under lease to a 
third party.
    (b) To ensure that you carry out G&G activities in a safe and 
environmentally sound manner so as to prevent harm or damage to, or 
waste of, any natural resources (including any mineral deposit in areas 
leased or not leased), any life (including fish and other aquatic 
life), property, or the marine, coastal, or human environment.
    (c) To inform you and third parties of your legal and contractual 
obligations.
    (d) To inform you and third parties of the U.S. Government's rights 
to access G&G data and information collected under permit in the OCS, 
reimbursement for submittal of data and information, and the 
proprietary terms of data and information submitted to, and retained 
by, BOEM.

Sec.  551.3  Authority and applicability of this part.

    BOEM authorizes you to conduct exploration or scientific research 
activities under this part in accordance with the Act, the regulations 
in this part, orders of the Director/Regional Director, and other 
applicable statutes, regulations, and amendments.
    (a) This part does not apply to G&G exploration conducted by or on 
behalf of the lessee on a lease in the OCS. Refer to 30 CFR part 250 if 
you plan to conduct G&G activities related to oil, gas, or sulphur 
under terms of a lease.
    (b) Federal agencies are exempt from the regulations in this part.
    (c) G&G exploration or G&G scientific research related to minerals 
other than oil, gas, and sulphur is covered by regulations at 30 CFR 
part 580.

Sec.  551.4  Types of G&G activities that require permits or Notices.

    (a) Exploration. You must have a BOEM-approved permit to conduct 
G&G exploration, including deep stratigraphic tests, for oil, gas, or

[[Page 64666]]

sulphur resources. If you conduct both geological and geophysical 
exploration, you must have a separate permit for each.
    (b) Scientific research. You may only conduct G&G scientific 
research related to oil, gas, and sulphur in the OCS after you obtain a 
BOEM-approved permit or file a Notice.
    (1) Permit. You must obtain a permit if the research activities you 
propose to conduct involve:
    (i) Using solid or liquid explosives;
    (ii) Drilling a deep stratigraphic test; or
    (iii) Developing data and information for proprietary use or sale.
    (2) Notice. Any other G&G scientific research that you conduct 
related to oil, gas, and sulphur in the OCS requires you to file a 
Notice with the Regional Director at least 30 days before you begin. If 
circumstances preclude a 30-day Notice, you must provide oral 
notification and followup in writing. You must also inform BOEM in 
writing when you conclude your work.

Sec.  551.5  Applying for permits or filing Notices.

    (a) Permits. You must submit a signed original and three copies of 
the BOEM permit application form (Form BOEM-0327). The form includes 
names of persons; the type, location, purpose, and dates of activity; 
and environmental and other information. A nonrefundable service fee of 
$2,012 must be paid electronically through Pay.gov at: https://www.pay.gov/paygov/, and you must include a copy of the Pay.gov 
confirmation receipt page with your application.
    (b) Disapproval of permit application. If BOEM disapproves your 
application for a permit, the Regional Director will state the reasons 
for the denial and will advise you of the changes needed to obtain 
approval.
    (c) Notices. You must sign and date a Notice and state:
    (1) The name(s) of the person(s) who will conduct the proposed 
research;
    (2) The name(s) of any other person(s) participating in the 
proposed research, including the sponsor;
    (3) The type of research and a brief description of how you will 
conduct it;
    (4) The location in the OCS, indicated on a map, plat, or chart, 
where you will conduct research;
    (5) The proposed dates you project for your research activity to 
start and end;
    (6) The name, registry number, registered owner, and port of 
registry of vessels used in the operation;
    (7) The earliest practicable time you expect to make the data and 
information resulting from your research activity available to the 
public;
    (8) Your plan of how you will make the data and information you 
collected available to the public;
    (9) That you and others involved will not sell or withhold for 
exclusive use the data and information resulting from your research; 
and
    (10) At your option, you may submit (as a substitute for the 
material required in paragraphs (c)(7), (c)(8), and (c)(9) of this 
section) the nonexclusive use agreement for scientific research 
attachment to Form BOEM-0327.
    (d) Filing locations. You must apply for a permit or file a Notice 
at one of the following locations:
    (1) For the OCS off the State of Alaska--the Regional Supervisor 
for Resource Evaluation, Bureau of Ocean Energy Management, Alaska OCS 
Region, 3801 Centerpoint Drive, Suite  500, Anchorage, Alaska 
99503-58232.
    (2) For the OCS off the Atlantic Coast and in the Gulf of Mexico--
the Regional Supervisor for Resource Evaluation, Bureau of Ocean Energy 
Management, Gulf of Mexico OCS Region, 1201 Elmwood Park Boulevard, New 
Orleans, Louisiana 70123-2394.
    (3) For the OCS off the coast of the States of California, Oregon, 
Washington, or Hawaii--the Regional Supervisor for Resource Evaluation, 
Bureau of Ocean Energy Management, Pacific OCS Region, 770 Paseo 
Camarillo, Camarillo, California 93010-6064.

Sec.  551.6  Obligations and rights under a permit or a Notice.

    While conducting G&G exploration or scientific research activities 
under BOEM permit or Notice:
    (a) You must not:
    (1) Interfere with or endanger operations under any lease, right-
of-way, easement, right-of-use, Notice, or permit issued or maintained 
under the Act;
    (2) Cause harm or damage to life (including fish and other aquatic 
life), property, or to the marine, coastal, or human environment;
    (3) Cause harm or damage to any mineral resource (in areas leased 
or not leased);
    (4) Cause pollution;
    (5) Disturb archaeological resources;
    (6) Create hazardous or unsafe conditions; or
    (7) Unreasonably interfere with or cause harm to other uses of the 
area.
    (b) You must immediately report to the Regional Director if you:
    (1) Detect hydrocarbon occurrences;
    (2) Detect environmental hazards which imminently threaten life and 
property; or
    (3) Adversely affect the environment, aquatic life, archaeological 
resources, or other uses of the area where you are conducting 
exploration or scientific research activities.
    (c) You must also consult and coordinate your G&G activities with 
other users of the area for navigation and safety purposes.
    (d) Any persons conducting shallow test drilling or deep 
stratigraphic test drilling activities under a permit must use the best 
available and safest technologies that the Regional Director determines 
to be economically feasible.
    (e) You may not claim any oil, gas, sulphur, or other minerals you 
discover while conducting operations under a permit or Notice.

Sec.  551.7  Test drilling activities under a permit.

    (a) Shallow test drilling. Before you begin shallow test drilling 
under a permit, the Regional Director may require you to:
    (1) Gather and submit seismic, bathymetric, sidescan sonar, 
magnetometer, or other geophysical data and information to determine 
shallow structural detail across and in the vicinity of the proposed 
test.
    (2) Submit information for coastal zone consistency certification 
according to paragraphs (b)(3) and (4) of this section, and for 
protecting archaeological resources according to paragraph (b)(5) of 
this section.
    (3) Allow all interested parties the opportunity to participate in 
the shallow test according to paragraph (c) of this section, and meet 
bonding requirements according to paragraph (d) of this section.
    (b) Deep stratigraphic tests. You must submit to the appropriate 
BOEM or BSEE Regional Director, at the address in Sec.  551.7(d), a 
drilling plan (submitted to BOEM), an environmental report (submitted 
to BOEM), an Application for Permit to Drill (Form BSEE-0123) 
(submitted to BSEE), and a Supplemental APD Information Sheet (Form 
BSEE-0123S) (submitted to BSEE) as follows:
    (1) Drilling plan. The drilling plan must include:
    (i) The proposed type, sequence, and timetable of drilling 
activities;
    (ii) A description of your drilling rig, indicating the important 
features with special attention to safety, pollution prevention, oil-
spill containment and cleanup plans, and onshore disposal procedures;
    (iii) The location of each deep stratigraphic test you will 
conduct, including the location of the surface and projected bottomhole 
of the borehole;
    (iv) The types of geological and geophysical survey instruments you 
will use before and during drilling;

[[Page 64667]]

    (v) Seismic, bathymetric, sidescan sonar, magnetometer, or other 
geophysical data and information sufficient to evaluate seafloor 
characteristics, shallow geologic hazards, and structural detail across 
and in the vicinity of the proposed test to the total depth of the 
proposed test well; and
    (vi) Other relevant data and information that the BOEM Regional 
Director requires.
    (2) Environmental report. The environmental report must include all 
of the following material:
    (i) A summary with data and information available at the time you 
submitted the related drilling plan. BOEM will consider site-specific 
data and information developed since the most recent environmental 
impact statement or other environmental impact analysis in the 
immediate area. The summary must meet the following requirements:
    (A) You must concentrate on the issues specific to the site(s) of 
drilling activity. However, you only need to summarize data and 
information discussed in any environmental reports, analyses, or impact 
statements prepared for the geographic area of the drilling activity.
    (B) You must list referenced material. Include brief descriptions 
and a statement of where the material is available for inspection.
    (C) You must refer only to data that are available to BOEM.
    (ii) Details about your project such as:
    (A) A list and description of new or unusual technologies;
    (B) The location of travel routes for supplies and personnel;
    (C) The kinds and approximate levels of energy sources;
    (D) The environmental monitoring systems; and
    (E) Suitable maps and diagrams showing details of the proposed 
project layout.
    (iii) A description of the existing environment. For this section, 
you must include the following information on the area:
    (A) Geology;
    (B) Physical oceanography;
    (C) Other uses of the area;
    (D) Flora and fauna;
    (E) Existing environmental monitoring systems; and
    (F) Other unusual or unique characteristics that may affect or be 
affected by the drilling activities.
    (iv) A description of the probable impacts of the proposed action 
on the environment and the measures you propose for mitigating these 
impacts.
    (v) A description of any unavoidable or irreversible adverse 
effects on the environment that could occur.
    (vi) Other relevant data that the BOEM Regional Director requires.
    (3) Copies for coastal States. You must submit copies of the 
drilling plan and environmental report to the BOEM Regional Director 
for transmittal to the Governor of each affected coastal State and the 
coastal zone management agency of each affected coastal State that has 
an approved program under the Coastal Zone Management Act. (BOEM 
Regional Director will make the drilling plan and environmental report 
available to appropriate Federal agencies and the public according to 
the Department of the Interior's policies and procedures).
    (4) Certification of coastal zone management program consistency 
and State concurrence. When required under an approved coastal zone 
management program of an affected State, your drilling plan must 
include a certification that the proposed activities described in the 
plan comply with enforceable policies of, and will be conducted in a 
manner consistent with such State's program. BOEM Regional Director may 
not approve any of the activities described in the drilling plan unless 
the State concurs with the consistency certification or the Secretary 
of Commerce makes the finding authorized by section 307(c)(3)(B)(iii) 
of the Coastal Zone Management Act.
    (5) Protecting archaeological resources. If the Regional Director 
believes that an archaeological resource may exist in the area that may 
be affected by drilling, the Regional Director will notify you of the 
need to prepare an archaeological report.
    (i) If the evidence suggests that an archaeological resource may be 
present, you must:
    (A) Locate the site of the drilling so as to not adversely affect 
the area where the archaeological resources may be, or
    (B) Establish to the satisfaction of the BOEM Regional Director 
that an archaeological resource does not exist or will not be adversely 
affected by drilling. This must be done by further archaeological 
investigation, conducted by an archaeologist and a geophysicist, using 
survey equipment and techniques deemed necessary by the Regional 
Director. A report on the investigation must be submitted to the BOEM 
Regional Director for review.
    (ii) If the BOEM Regional Director determines that an 
archaeological resource is likely to be present in the area that may be 
affected by drilling, and may be adversely affected by drilling, the 
BOEM Regional Director will notify you immediately. You must take no 
action that may adversely affect the archaeological resource unless an 
investigation by BOEM determines that the resource is not 
archaeologically significant.
    (iii) If you discover any archaeological resource while drilling, 
you must immediately halt drilling and report the discovery to the BOEM 
Regional Director. If investigations determine that the resource is 
significant, the BOEM Regional Director will inform you how to protect 
it.
    (6) [Reserved]
    (7) Revising an approved drilling plan. Before you revise an 
approved drilling plan, you must obtain the BOEM Regional Director's 
approval.
    (8) [Reserved]
    (9) Deadline for completing a deep stratigraphic test. If your deep 
stratigraphic test well is within 50 geographic miles of a tract that 
BOEM has identified for a future lease sale, as listed on the currently 
approved OCS leasing schedule, you must complete all drilling 
activities and submit the data and information to the BOEM Regional 
Director at least 60 days before the first day of the month in which 
BOEM schedules the lease sale. However, the BOEM Regional Director may 
extend your permit duration to allow you to complete drilling 
activities and submit data and information if the extension is in the 
National interest.
    (c) Group participation in test drilling. BOEM encourages group 
participation for deep stratigraphic tests.
    (1) Purpose of group participation. The purpose is to minimize 
duplicative G&G activities involving drilling into the seabed of the 
OCS.
    (2) Providing opportunity for participation in a deep stratigraphic 
test. When you propose to drill a deep stratigraphic test, you must 
give all interested persons an opportunity to participate in the test 
drilling through a signed agreement on a cost-sharing basis. You may 
include a penalty for late participation of not more than 100 percent 
of the cost to each original participant in addition to the original 
share cost.
    (i) The participants must assess and distribute late participation 
penalties in accordance with the terms of the agreement.
    (ii) For a significant hydrocarbon occurrence that the Regional 
Director announces to the public, the penalty for subsequent late 
participants may be raised to not more than 300 percent of the cost of 
each original participant in addition to the original share cost.
    (3) Providing opportunity for participation in a shallow test 
drilling

[[Page 64668]]

project. When you apply to conduct shallow test drilling activities, 
you must, if ordered by the Regional Director or required by the 
permit, give all interested persons an opportunity to participate in 
the test activity on a cost-sharing basis. You may include a penalty 
provision for late participation of not more than 50 percent of the 
cost to each original participant in addition to the original share 
cost.
    (4) Procedures for group participation in drilling activities. You 
must:
    (i) Publish a summary statement that describes the approved 
activity in a relevant trade publication;
    (ii) Forward a copy of the published statement to the Regional 
Director;
    (iii) Allow at least 30 days from the summary statement publication 
date for other persons to join as original participants;
    (iv) Compute the estimated cost by dividing the estimated total 
cost of the program by the number of original participants; and
    (v) Furnish the Regional Director with a complete list of all 
participants before starting operations, or at the end of the 
advertising period if you begin operations before the advertising 
period is over. The names of any subsequent or late participants must 
also be furnished to the Regional Director.
    (5) Changes to the original application for test drilling. If you 
propose changes to the original application and the Regional Director 
determines that the changes are significant, the Regional Director will 
require you to publish the changes for an additional 30 days to give 
other persons a chance to join as original participants.
    (d) Bonding requirements. You must submit a bond under this part 
before you may start a deep stratigraphic test.
    (1) Before BOEM issues a permit authorizing the drilling of a deep 
stratigraphic test, you must either:
    (i) Furnish to BOEM a bond of not less than $200,000 that 
guarantees compliance with all the terms and conditions of the permit; 
or
    (ii) Maintain a $1 million bond that guarantees compliance with all 
the terms and conditions of the permit you hold for the OCS area where 
you propose to drill.
    (2) You must provide additional security to BOEM if the Regional 
Director determines that it is necessary for the permit or area.
    (3) The Regional Director may require you to provide a bond, in an 
amount the Regional Director prescribes, before authorizing you to 
drill a shallow test well.
    (4) Your bond must be on a form approved by the Associate Director 
for BOEM.

Sec.  551.8  Inspection and reporting requirements for activities under 
a permit.

    (a) Inspection of permit activities. You must allow BOEM 
representatives to inspect your exploration or scientific research 
activities under a permit. They will determine whether operations are 
adversely affecting the environment, aquatic life, archaeological 
resources, or other uses of the area. BOEM will reimburse you for food, 
quarters, and transportation that you provide for BOEM representatives 
if you send in your reimbursement request to the Region that issued the 
permit within 90 days of the inspection.
    (b) Approval for modifications. Before you begin modified 
operations, you must submit a written request describing the 
modifications and receive the Regional Director's oral or written 
approval. If circumstances preclude a written request, you must make an 
oral request and follow up in writing.
    (c) Reports. (1) You must submit status reports on a schedule 
specified in the permit and include a daily log of operations.
    (2) You must submit a final report of exploration or scientific 
research activities under a permit within 30 days after the completion 
of acquisition activities under the permit. You may combine the final 
report with the last status report and must include each of the 
following:
    (i) A description of the work performed.
    (ii) Charts, maps, plats, and digital navigational data in a format 
specified by the Regional Director, showing the areas and blocks in 
which any exploration or permitted scientific research activities were 
conducted. Identify the lines of geophysical traverses and their 
locations including a reference sufficient to identify the data 
produced during each activity.
    (iii) The dates on which you conducted the actual exploration or 
scientific research activities.
    (iv) A summary of any:
    (A) Hydrocarbon or sulphur occurrences encountered;
    (B) Environmental hazards; and
    (C) Adverse effects of the exploration or scientific research 
activities on the environment, aquatic life, archaeological resources, 
or other uses of the area in which the activities were conducted.
    (v) Other descriptions of the activities conducted as specified by 
the Regional Director.

Sec.  551.9  Temporarily stopping, canceling, or relinquishing 
activities approved under a permit.

    (a) BOEM may temporarily stop exploration or scientific research 
activities under a permit when the Regional Director determines that:
    (1) Activities pose a threat of serious, irreparable, or immediate 
harm. This includes damage to life (including fish and other aquatic 
life), property, any mineral deposit (in areas leased or not leased), 
to the marine, coastal, or human environment, or to an archaeological 
resource;
    (2) You failed to comply with any applicable law, regulation, 
order, or provision of the permit. This would include BOEM's required 
submission of reports, well records or logs, and G&G data and 
information within the time specified; or
    (3) Stopping the activities is in the interest of National security 
or defense.
    (b) Procedures to temporarily stop activities. (1) The Regional 
Director will advise you either orally or in writing. BOEM will confirm 
an oral notification in writing and deliver all written notifications 
by courier or certified or registered mail. You must halt all 
activities under a permit as soon as you receive an oral or written 
notification.
    (2) The Regional Director will advise you when you may start your 
permit activities again.
    (c) Procedure to cancel or relinquish a permit. The Regional 
Director may cancel, or a permittee may relinquish, a permit at any 
time.
    (1) If BOEM cancels your permit, the Regional Director will advise 
you by certified or registered mail 30 days before the cancellation 
date and will state the reason.
    (2) You may relinquish the permit by advising the Regional Director 
by certified or registered mail 30 days in advance.
    (3) After BOEM cancels your permit or you relinquish it, you are 
still responsible for proper abandonment of any drill sites in 
accordance with the requirements of 30 CFR 251.7(b)(8). You must also 
comply with all other obligations specified in this part or in the 
permit.

Sec.  551.10  Penalties and appeals.

    (a) Penalties for noncompliance under a permit issued by BOEM. You 
are subject to the penalty provisions of:
    (1) Section 24 of the Act (43 U.S.C. 1350); and
    (2) The procedures contained in 30 CFR part 550, subpart N, for 
noncompliance with:
    (i) Any provision of the Act;
    (ii) Any provision of a G&G or drilling permit; or

[[Page 64669]]

    (iii) Any regulation or order issued under the Act.
    (b) Penalties under other laws and regulations. The penalties 
prescribed in this section are in addition to any other penalty imposed 
by any other law or regulation.
    (c) Procedures to appeal orders or decisions BOEM issues. See 30 
CFR part 590 for instructions on how to appeal any order or decision 
that we issue under this part.

Sec.  551.11  Submission, inspection, and selection of geological data 
and information collected under a permit and processed by permittees or 
third parties.

    (a) Availability of geological data and information collected under 
a permit. (1) You must notify the Regional Director, in writing, when 
you complete the initial analysis, processing, or interpretation of any 
geological data and information. Initial analysis and processing are 
the stages of analysis or processing where the data and information 
first become available for in-house interpretation by the permittee, or 
become available commercially to third parties via sale, trade, license 
agreement, or other means.
    (2) The Regional Director may ask if you have further analyzed, 
processed, or interpreted any geological data and information. When so 
asked, you must respond to BOEM in writing within 30 days.
    (b) Submission, inspection, and selection of geological data and 
information. The Regional Director may request the permittee or third 
party to submit the analyzed, processed, and interpreted geologic data 
and information for inspection and/or permanent retention by BOEM. The 
data and information must be submitted within 30 days after such 
request.
    (c) Requirements for submission of geological data and information 
collected under a permit. Unless the Regional Director specifies 
otherwise, geological data and information must include:
    (1) An accurate and complete record of all geological (including 
geochemical) data and information describing each operation of 
analysis, processing, and interpretation;
    (2) Paleontological reports identifying microscopic fossils by 
depth, including the reference datum to which paleontological sample 
depths are related and, if the Regional Director requests, washed 
samples that you maintain for paleontological determinations;
    (3) Copies of well logs or charts in a digital format, if 
available;
    (4) Results and data obtained from formation fluid tests;
    (5) Analyses of core or bottom samples and/or a representative cut 
or split of the core or bottom sample;
    (6) Detailed descriptions of any hydrocarbons or hazardous 
conditions encountered during operations, including near losses of well 
control, abnormal geopressures, and losses of circulation; and
    (7) Other geological data and information that the Regional 
Director may specify.
    (d) Obligations when geological data and information collected 
under permit are obtained by a third party. A third party may obtain 
geological data and information from a permittee, or from another third 
party, by sale, trade, license agreement, or other means. If this 
happens:
    (1) The third party recipient of the data and information assumes 
the obligations under this section, except for the notification 
provisions of paragraph (a)(1), and is subject to the penalty 
provisions of 30 CFR part 550, subpart N; and
    (2) A permittee or third party that sells, trades, licenses, or 
otherwise provides data and information to a third party must advise 
the recipient, in writing, that accepting these obligations is a 
condition precedent of the sale, trade, license, or other agreement; 
and
    (3) Except for license agreements, a permittee or third party that 
sells, trades, or otherwise provides data and information to a third 
party must advise the Regional Director, in writing and within 30 days, 
of the sale, trade, or other agreement, including the identity of the 
recipient of the data and information; or
    (4) For license agreements a permittee or third party that licenses 
data and information to a third party must, within 30 days of a request 
by the Regional Director, advise the Regional Director, in writing, of 
the license agreement, including the identity of the recipient of the 
data and information.

Sec.  551.12  Submission, inspection, and selection of geophysical data 
and information collected under a permit and processed by permittees or 
third parties.

    (a) Availability of geophysical data and information collected 
under a permit. (1) You must notify the Regional Director, in writing, 
when you complete the initial processing and interpretation of any 
geophysical data and information. Initial processing is the stage of 
processing where the data and information become available for in-house 
interpretation by the permittee, or become available commercially to 
third parties via sale, trade, license agreement, or other means.
    (2) The Regional Director may ask if you have further processed or 
interpreted any geophysical data and information. When so asked, you 
must respond to BOEM in writing within 30 days.
    (b) Submission, inspection and selection of geophysical data and 
information collected under a permit. The Regional Director may request 
that the permittee or third party submit geophysical data and 
information before making a final selection for retention. BOEM 
representatives may inspect and select the data and information on your 
premises, or the Regional Director can request delivery of the data and 
information to the appropriate BOEM regional office for review.
    (1) You must submit the geophysical data and information within 30 
days of receiving the request, unless the Regional Director extends the 
delivery time.
    (2) At any time before final selection, the Regional Director may 
return any or all geophysical data and information following review. 
You will be notified in writing of all or portions of those data the 
Regional Director decides to retain.
    (c) Requirements for submission of geophysical data and information 
collected under a permit. Unless the Regional Director specifies 
otherwise, you must include:
    (1) An accurate and complete record of each geophysical survey 
conducted under the permit, including digital navigational data and 
final location maps;
    (2) All seismic data collected under a permit presented in a format 
and of a quality suitable for processing;
    (3) Processed geophysical information derived from seismic data 
with extraneous signals and interference removed, presented in a 
quality format suitable for interpretive evaluation, reflecting state-
of-the-art processing techniques; and
    (4) Other geophysical data, processed geophysical information, and 
interpreted geophysical information including, but not limited to, 
shallow and deep subbottom profiles, bathymetry, sidescan sonar, 
gravity and magnetic surveys, and special studies such as refraction 
and velocity surveys.
    (d) Obligations when geophysical data and information collected 
under a permit are obtained by a third party. A third party may obtain 
geophysical data, processed geophysical information, or interpreted 
geophysical information from a permittee, or from another third party, 
by sale, trade, license agreement, or other means. If this happens:
    (1) The third party recipient of the data and information assumes 
the

[[Page 64670]]

obligations under this section, except for the notification provisions 
of paragraph (a)(1), and is subject to the penalty provisions of 30 CFR 
part 550, subpart N; and
    (2) A permittee or third party that sells, trades, licenses, or 
otherwise provides data and information to a third party must advise 
the recipient, in writing, that accepting these obligations is a 
condition precedent of the sale, trade, license, or other agreement; 
and
    (3) Except for license agreements, a permittee or third party that 
sells, trades, or otherwise provides data and information to a third 
party must advise the Regional Director, in writing and within 30 days, 
of the sale, trade, or other agreement, including the identity of the 
recipient of the data and information; or
    (4) For license agreements, a permittee or third party that 
licenses data and information to a third party must, within 30 days of 
a request by the Regional Director, advise the Regional Director, in 
writing, of the license agreement, including the identity of the 
recipient of the data and information.

Sec.  551.13  Reimbursement for the costs of reproducing data and 
information and certain processing costs.

    (a) BOEM will reimburse you or a third party for reasonable costs 
of reproducing data and information that the Regional Director requests 
if:
    (1) You deliver G&G data and information to BOEM for the Regional 
Director to inspect or select and retain (according to Sec. Sec.  
551.11 or 551.12);
    (2) BOEM receives your request for reimbursement and the Regional 
Director determines that the requested reimbursement is proper; and
    (3) The cost is at your lowest rate (or a third party's) or at the 
lowest commercial rate established in the area, whichever is less.
    (b) BOEM will reimburse you or the third party for the reasonable 
costs of processing geophysical information (which does not include 
cost of data acquisition):
    (1) If, at the request of the Regional Director, you processed the 
geophysical data or information in a form or manner other than that 
used in the normal conduct of business; or
    (2) If you collected the information under a permit that BOEM 
issued to you before October 1, 1985, and the Regional Director 
requests and retains the information.
    (c) When you request reimbursement, you must identify reproduction 
and processing costs separately from acquisition costs.
    (d) BOEM will not reimburse you or a third party for data 
acquisition costs or for the costs of analyzing or processing 
geological information or interpreting geological or geophysical 
information.

Sec.  551.14  Protecting and disclosing data and information submitted 
to BOEM under a permit.

    (a) Disclosure of data and information to the public by BOEM. (1) 
In making data and information available to the public, the Regional 
Director will follow the applicable requirements of:
    (i) The Freedom of Information Act (5 U.S.C. 552);
    (ii) The implementing regulations at 43 CFR part 2;
    (iii) The Act; and
    (iv) The regulations at 30 CFR parts 550 and 552.
    (2) Except as specified in this section or in 30 CFR parts 550 and 
552, if the Regional Director determines any data or information is 
exempt from public disclosure under this paragraph (a), BOEM will not 
provide the data and information to any State or to the executive of 
any local government or to the public, unless you and all third parties 
agree to the disclosure.
    (3) BOEM will keep confidential the identity of third party 
recipients of data and information collected under a permit. BOEM will 
not release the identity unless you and the third parties agree to the 
disclosure.
    (4) When you detect any significant hydrocarbon occurrences or 
environmental hazards on unleased lands during drilling operations, the 
Regional Director will immediately issue a public announcement. The 
announcement must further the National interest, but without unduly 
damaging your competitive position.
    (b) Timetable for release of G&G data and information related to 
oil, gas, and sulphur that BOEM acquires. Except for high-resolution 
data and information released under 30 CFR 550.197(b)(2), BOEM will 
release or disclose acquired data and information in accordance with 
paragraphs (b)(1) through (7) of this section.
    (1) If the data and information are not related to a deep 
stratigraphic test, BOEM will release them to the public in accordance 
with the following table:

------------------------------------------------------------------------
                                            The Regional Director will
If you or a third party submit and BOEM   release them to the public . .
             retains . . .                              .
------------------------------------------------------------------------
(i) Geological data and information,     10 years after BOEM issued the
                                          permit.
(ii) Geophysical data,                   50 years after BOEM issued the
                                          permit.
(iii) Geophysical information processed  25 years after BOEM issued the
 or reprocessed less than 20 years        permit.
 after BOEM issued the germane permit,
(iv) Geophysical information processed   25 years after BOEM issued the
 or reprocessed 20 or more years after    permit; or, if you or a third
 BOEM issued the germane permit,          party applied for an extension
                                          of the proprietary term, 5
                                          years after BOEM approved the
                                          application for an extension.
                                          In any case BOEM will release
                                          the information no later than
                                          50 years after BOEM issued the
                                          permit.
------------------------------------------------------------------------

     (2) Permittees and third parties may apply to BOEM for an 
extension of the 25-year proprietary term for geophysical information 
reprocessed 20 or more years after BOEM issued the germane permit. You 
must submit the application to BOEM within 90 days after completion of 
the reprocessing, except during the initial 1-year grace period as 
provided in paragraph (b)(5) below. Filing locations are listed in 
Sec.  551.5(d). Your application must include:
    (i) Name and address of the permittee or third party;
    (ii) Product name;
    (iii) Identification of the geophysical information area;
    (iv) Identification of originating permit number and date;
    (v) Description of reprocessing performed;
    (vi) Identification of the date of completion of reprocessing the 
geophysical information;
    (vii) Certification that the product meets the definition of 
processed geophysical information and that all other information in the 
application is accurate; and
    (viii) Signature and date.
    (3) With each new reprocessing of permitted data, you may apply for 
an extension of up to 5 years. However, the

[[Page 64671]]

maximum proprietary term for geophysical information is 50 years after 
the permit was issued. Once the maximum term is reached, the BOEM 
Regional Director will release the information to the public.
    (4) Geophysical information processed or reprocessed 20 or more 
years after the germane permit was issued and granted the extension 
will be subject to submission, inspection, and selection criteria under 
Sec.  551.12 and reimbursement criteria identified under Sec.  551.13.
    (5) There was a 1-year grace period, that started September 14, 
2009, that allowed permittees and third parties sufficient time to meet 
the above requirements and apply for all eligible extensions. During 
that time, BOEM did not release geophysical information which was 
reprocessed 20 or more years after the date that the germane permit was 
issued.
    (6) Since September 14, 2010, BOEM has resumed releasing eligible 
reprocessed information. If an application for extension was not filed, 
not filed on time, or not approved by BOEM, the original 25-year 
proprietary term applies to the release date of the reprocessed 
geophysical information.
    (7) If the data and information are related to a deep stratigraphic 
test, BOEM will release them to the public at the earlier of the 
following times:
    (i) Twenty-five years after you complete the test; or
    (ii) If a lease sale is held after you complete a test well, 60-
calendar days after BOEM issues the first lease, any portion of which 
is located within 50 geographic miles (92.7 kilometers) of the test.
    (8) BOEM may allow limited inspection, but only by persons with a 
direct interest in related BOEM decisions and issues in specific 
geographic areas, and who agree in writing to its confidentiality, of 
G&G data and information submitted under this part that BOEM uses to:
    (i) Make unitization determinations on two or more leases;
    (ii) Make competitive reservoir determinations;
    (iii) Ensure proper plans of development for competitive 
reservoirs;
    (iv) Promote operational safety;
    (v) Protect the environment;
    (vi) Make field determinations; or
    (vii) Determine eligibility for royalty relief.
    (c) Procedure that BOEM follows to disclose acquired data and 
information to a contractor for reproduction, processing, and 
interpretation. (1) When practical, the Regional Director will advise 
the person who submitted data and information under Sec.  551.11 or 
Sec.  551.12 of the intent to disclose the data or information to an 
independent contractor or agent.
    (2) The person so notified will have at least 5 working days to 
comment on the action.
    (3) When the Regional Director advises the person who submitted the 
data and information, all other owners of the data or information will 
be considered to have been so notified.
    (4) Before disclosure, the contractor or agent must sign a written 
commitment not to sell, trade, license, or disclose data or information 
to anyone without the Regional Director's consent.
    (d) Sharing data and information with coastal States. (1) When BOEM 
solicits nominations for leasing lands located within 3 geographic 
miles (5.6 kilometers) of the seaward boundary of any coastal State, 
the Regional Director, in accordance with 30 CFR 552.7(a)(4) and (b) 
and subsections 8(g) and 26(e) of the Act (43 U.S.C. 1337(g) and 
1352(e)), will provide the Governor with:
    (i) All information on the geographical, geological, and ecological 
characteristics of the areas and regions BOEM proposes to offer for 
lease;
    (ii) An estimate of the oil and gas reserves in the areas proposed 
for leasing; and
    (iii) An identification of any field, geological structure, or trap 
on the OCS within 3 geographic miles (5.6 kilometers) of the seaward 
boundary of the State.
    (2) After receiving nominations for leasing an area of the OCS 
within 3 geographic miles of the seaward boundary of any coastal State, 
BOEM will carry out a tentative area identification according to 30 CFR 
part 556, subparts D and E. At that time, the Regional Director will 
consult with the Governor to determine whether any tracts further 
considered for leasing may contain any oil or gas reservoirs that 
underlie both the OCS and lands subject to the jurisdiction of the 
State.
    (3) Before a sale, if a Governor requests, the Regional Director, 
in accordance with 30 CFR 552.7(a)(4) and (b) and sections 8(g) and 
26(e) of the Act (43 U.S.C. 1337(g) and 1352(e)), will share with the 
Governor information that identifies potential and/or proven common 
hydrocarbon bearing areas within 3 geographic miles of the seaward 
boundary of that State.
    (4) Information received and knowledge gained by a State official 
under paragraph (d) of this section is subject to applicable 
confidentiality requirements of:
    (i) The Act; and
    (ii) The regulations at 30 CFR parts 550, 551, and 552.

Sec.  551.15  Authority for information collection.

    (a) The Office of Management and Budget has approved the 
information collection requirements in this part under 44 U.S.C. 3501 
et seq. and assigned OMB control number 1010-0048. The title of this 
information collection is ``30 CFR part 551, Geological and Geophysical 
(G&G) Explorations of the OCS.''
    (b) We may not conduct or sponsor, and you are not required to 
respond to, a collection of information unless it displays a currently 
valid OMB control number.
    (c) We use the information collected under this part to:
    (1) Evaluate permit applications and monitor scientific research 
activities for environmental and safety reasons.
    (2) Determine that explorations do not harm resources, result in 
pollution, create hazardous or unsafe conditions, or interfere with 
other users in the area.
    (3) Approve reimbursement of certain expenses.
    (4) Monitor the progress and activities carried out under an OCS 
G&G permit.
    (5) Inspect and select G&G data and information collected under an 
OCS G&G permit.
    (d) Respondents are Federal OCS permittees and Notice filers. 
Responses are mandatory or are required to obtain or retain a benefit. 
We will protect information considered proprietary under applicable law 
and under regulations at Sec.  551.14 and part 550 of this chapter.
    (e) Send comments regarding any aspect of the collection of 
information under this part, including suggestions for reducing the 
burden, to the Information Collection Clearance Officer, Bureau of 
Ocean Energy Management, 381 Elden Street, Herndon, VA 20170.

PART 552--OUTER CONTINENTAL SHELF (OCS) OIL AND GAS INFORMATION 
PROGRAM

Sec.
552.1 Purpose.
552.2 Definitions.
552.3 Oil and gas data and information to be provided for use in the 
OCS Oil and Gas Information Program.
552.4 Summary Report to affected States.
552.5 Information to be made available to affected States.
552.6 Freedom of Information Act requirements.
552.7 Privileged and proprietary data and information to be made 
available to affected States.

[[Page 64672]]

    Authority: OCS Lands Act, 43 U.S.C. 1331 et seq., as amended, 92 
Stat. 629; Freedom of Information Act, 5 U.S.C. 552; Sec.  252.3 
also issued under Pub. L. 99-190 making continuing appropriations 
for Fiscal Year 1986, and for other purposes.

Sec.  552.1  Purpose.

    The purpose of this part is to implement the provisions of section 
26 of the Act (43 U.S.C. 1352). This part supplements the procedures 
and requirements contained in 30 CFR parts 250, 251, 550, and 551 and 
provides procedures and requirements for the submission of oil and gas 
data and information resulting from exploration, development, and 
production operations on the Outer Continental Shelf (OCS) to the 
Director, Bureau of Ocean Energy Management. In addition, this part 
establishes procedures for the Director to make available certain 
information to the Governors of affected States and, upon request, to 
the executives of affected local governments in accordance with the 
provisions of the Freedom of Information Act and the Act.

Sec.  552.2  Definitions.

    When used in the regulations in this part, the following terms 
shall have the meanings given below:
    Act refers to the Outer Continental Shelf Lands Act, as amended (43 
U.S.C. 1331 et seq.).
    Affected local government means the principal governing body of a 
locality which is in an affected State and is identified by the 
Governor of that State as a locality which will be significantly 
affected by oil and gas activities on the OCS.
    Affected State means, with respect to any program, plan, lease 
sale, or other activity, proposed, conducted, or approved pursuant to 
the provisions of the Act, any State:
    (1) The laws of which are declared, pursuant to section 4(a)(2)(A) 
of the Act, to be the law of the United States for the portion of the 
OCS on which such activity is, or is proposed to be, conducted;
    (2) Which is, or is proposed to be, directly connected by 
transportation facilities to any artificial island or installations and 
other devices permanently, or temporarily attached to the seabed;
    (3) Which is receiving, or in accordance with the proposed activity 
will receive, oil for processing, refining, or transshipment which was 
extracted from the OCS and transported directly to such State by means 
of vessels or by a combination of means including vessels;
    (4) Which is designated by the Director as a State in which there 
is a substantial probability of significant impact on or damage to the 
coastal, marine, or human environment, or a State in which there will 
be significant changes in the social, governmental, or economic 
infrastructure, resulting from the exploration, development, and 
production of oil and gas anywhere on the OCS; or
    (5) In which the Director finds that because of such activity there 
is, or will be, a significant risk of serious damage, due to factors 
such as prevailing winds and currents, to the marine or coastal 
environment in the event of any oilspill, blowout, or release of oil or 
gas from vessels, pipelines, or other transshipment facilities.
    Analyzed geological information means data collected under a permit 
or a lease which have been analyzed. Analysis may include, but is not 
limited to, identification of lithologic and fossil content, core 
analyses, laboratory analyses of physical and chemical properties, logs 
or charts of electrical, radioactive, sonic, and other well logs, and 
descriptions of hydrocarbon shows or hazardous conditions.
    Area adjacent to a State means all of that portion of the OCS 
included within a planning area if such planning area is bordered by 
that State. The portion of the OCS in the Navarin Basin Planning Area 
is deemed to be adjacent to the State of Alaska. The States of New York 
and Rhode Island are deemed to be adjacent to both the Mid-Atlantic 
Planning Area and the North Atlantic Planning Area.
    Data means facts and statistics or samples which have not been 
analyzed or processed.
    Development means those activities which take place following 
discovery of oil or natural gas in paying quantities, including 
geophysical activity, drilling, platform construction, and operation of 
all onshore support facilities, and which are for the purpose of 
ultimately producing the oil and gas discovered.
    Director means the Director of the Bureau of Ocean Energy 
Management of the U.S. Department of the Interior or a designee of the 
Director.
    Exploration means the process of searching for oil and natural gas, 
including:
    (1) Geophysical surveys where magnetic, gravity, seismic, or other 
systems are used to detect or imply the presence of such oil or natural 
gas, and
    (2) Any drilling, whether on or off known geological structures, 
including the drilling of a well in which a discovery of oil or natural 
gas in paying quantities is made and the drilling of any additional 
delineation well after such discovery which is needed to delineate any 
reservoir and to enable the lessee to determine whether to proceed with 
development and production.
    Governor means the Governor of a State, or the person or entity 
designated by, or pursuant to, State law to exercise the powers granted 
to a Governor pursuant to the Act.
    Information, when used without a qualifying adjective, includes 
analyzed geological information, processed geophysical information, 
interpreted geological information, and interpreted geophysical 
information.
    Interpreted geological information means knowledge, often in the 
form of schematic cross sections and maps, developed by determining the 
geological significance of data and analyzed geological information.
    Interpreted geophysical information means knowledge, often in the 
form of schematic cross sections and maps, developed by determining the 
geological significance of geophysical data and processed geophysical 
information.
    Lease means any form of authorization which is issued under section 
8 or maintained under section 6 of the Act and which authorizes 
exploration for, and development and production of, oil or natural gas, 
or the land covered by such authorization, whichever is required by the 
context.
    Lessee means the party authorized by a lease, or an approved 
assignment thereof, to explore for and develop and produce the leased 
deposits in accordance with the regulations in part 550 of this 
chapter, including all parties holding such authority by or through the 
lessee.
    Outer Continental Shelf (OCS) means all submerged lands which lie 
seaward and outside of the area of lands beneath navigable waters as 
defined in the Submerged Lands Act (67 Stat. 29) and of which the 
subsoil and seabed appertain to the United States and are subject to 
its jurisdiction and control.
    Permittee means the party authorized by a permit issued pursuant to 
part 551 of this chapter to conduct activities on the OCS.
    Processed geophysical information means data collected under a 
permit or a lease which have been processed. Processing involves 
changing the form of data so as to facilitate interpretation. 
Processing operations may include, but are not limited to, applying 
corrections for known perturbing causes, rearranging or filtering data, 
and combining or transforming data elements.
    Production means those activities which take place after the 
successful

[[Page 64673]]

completion of any means for the removal of oil or natural gas, 
including such removal, field operations, transfer of oil or natural 
gas to shore, operation monitoring, maintenance, and workover drilling.
    Secretary means the Secretary of the Interior or a designee of the 
Secretary.

Sec.  552.3  Oil and gas data and information to be provided for use in 
the OCS Oil and Gas Information Program.

    (a) Any permittee or lessee engaging in the activities of 
exploration for, or development and production of, oil and gas on the 
OCS shall provide the Director access to all data and information 
obtained or developed as a result of such activities, including 
geological data, geophysical data, analyzed geological information, 
processed and reprocessed geophysical information, interpreted 
geophysical information, and interpreted geological information. Copies 
of these data and information and any interpretation of these data and 
information shall be provided to the Director upon request. No 
permittee or lessee submitting an interpretation of data or 
information, where such interpretation has been submitted in good 
faith, shall be held responsible for any consequence of the use of or 
reliance upon such interpretation.
    (b)(1) Whenever a lessee or permittee provides any data or 
information, at the request of the Director and specifically for use in 
the OCS Oil and Gas Information Program in a form and manner of 
processing which is utilized by the lessee or permittee in the normal 
conduct of business, the Director shall pay the reasonable cost of 
reproducing the data and information if the lessee or permittee 
requests reimbursement. The cost shall be computed and paid in 
accordance with the applicable provisions of paragraph (e)(1) of this 
section.
    (2) Whenever a lessee or permittee provides any data or 
information, at the request of the Director and specifically for use in 
the OCS Oil and Gas Information Program, in a form and manner of 
processing not normally utilized by the lessee or permittee in the 
normal conduct of business, the Director shall pay the lessee or 
permittee, if the lessee or permittee requests reimbursement, the 
reasonable cost of processing and reproducing the requested data and 
information. The cost is to be computed and paid in accordance with the 
applicable provisions of paragraph (e)(2) of this section.
    (c) Data or information requested by the Director shall be provided 
as soon as practicable, but not later than 30 days following receipt of 
the Director's request, unless, for good reason, the Director 
authorizes a longer time period for the submission of the requested 
data or information.
    (d) The Director reserves the right to disclose any data or 
information acquired from a lessee or permittee to an independent 
contractor or agent for the purpose of reproducing, processing, 
reprocessing, or interpreting such data or information. When 
practicable, the Director shall notify the lessee(s) or permittee(s) 
who provided the data or information of the intent to disclose the data 
or information to an independent contractor or agent. The Director's 
notice of intent will afford the permittee(s) or lessee(s) a period of 
not less than 5 working days within which to comment on the intended 
action. When the Director so notifies a lessee or permittee of the 
intent to disclose data or information to an independent contractor or 
agent, all other owners of such data or information shall be deemed to 
have been notified of the Director's intent. Prior to any such 
disclosure, the contractor or agent shall be required to execute a 
written commitment not to disclose any data or information to anyone 
without the express consent of the Director, and not to make any 
disclosure or use of the data or information other than that provided 
in the contract. Contracts between BOEM and independent contractors 
shall be available to the lessee(s) or permittee(s) for inspection. In 
the event of any unauthorized use or disclosure of data or information 
by the contractor or agent, or by an employee thereof, the responsible 
contractor or agent or employee thereof shall be liable for penalties 
pursuant to section 24 of the Act.
    (e)(1) After delivery of data or information in accordance with 
paragraph (b)(1) of this section and upon receipt of a request for 
reimbursement and a determination by the Director that the requested 
reimbursement is proper, the lessee or permittee shall be reimbursed 
for the cost of reproducing the data or information at the lessee's or 
permittee's lowest rate or at the lowest commercial rate established in 
the area, whichever is less. Requests for reimbursement must be made 
within 60 days of the delivery date of the data or information 
requested under paragraph (b)(1) of this section.
    (2) After delivery of data or information in accordance with 
paragraph (b)(3) of this section, and upon receipt of a request for 
reimbursement and a determination by the Director that the requested 
reimbursement is proper, the lessee or permittee shall be reimbursed 
for the cost of processing or reprocessing and of reproducing the 
requested data or information. Requests for reimbursement must be made 
within 60 days of the delivery date of the data or information and 
shall be for only the costs attributable to processing or reprocessing 
and reproducing, as distinguished from the costs of data acquisition.
    (3) Requests for reimbursement are to contain a breakdown of costs 
in sufficient detail to allow separation of reproduction, processing, 
and reprocessing costs from acquisition and other costs.
    (f) Each Federal Department or Agency shall provide the Director 
with any data which it has obtained pursuant to section 11 of the Act 
and any other information which may be necessary or useful to assist 
the Director in carrying out the provisions of the Act.

Sec.  552.4  Summary Report to affected States.

    (a) The Director, as soon as practicable after analysis, 
interpretation, and compilation of oil and gas data and information 
developed by BOEM or furnished by lessees, permittees, or other 
government agencies, shall make available to affected States and, upon 
request, to the executive of any affected local government, a Summary 
Report of data and information designed to assist them in planning for 
the onshore impacts of potential OCS oil and gas development and 
production. The Director shall consult with affected States and other 
interested parties to define the nature, scope, content, and timing of 
the Summary Report. The Director may consult with affected States and 
other interested parties regarding subsequent revisions in the 
definition of the nature, scope, content, and timing of the Summary 
Report. The Summary Report shall not contain data or information which 
the Director determines is exempt from disclosure in accordance with 
this part. The Summary Report shall not contain data or information the 
release of which the Director determines would unduly damage the 
competitive position of the lessee or permittee who provided the data 
or information which the Director has processed, analyzed, or 
interpreted during the development of the Summary Report. The Summary 
Report shall include:
    (1) Estimates of oil and gas reserves; estimates of the oil and gas 
resources that may be found within areas which the Secretary has leased 
or plans to offer

[[Page 64674]]

for lease; and when available, projected rates and volumes of oil and 
gas to be produced from leased areas;
    (2) Magnitude of the approximate projections and timing of 
development, if and when oil or gas, or both, is discovered;
    (3) Methods of transportation to be used, including vessels and 
pipelines and approximate location of routes to be followed; and
    (4) General location and nature of near-shore and onshore 
facilities expected to be utilized.
    (b) When the Director determines that significant changes have 
occurred in the information contained in a Summary Report, the Director 
shall prepare and make available the new or revised information to each 
affected State, and, upon request, to the executive of any affected 
local government.

Sec.  552.5  Information to be made available to affected States.

    (a) The Director shall prepare an index of OCS information (see 30 
CFR 556.10). The index shall list all relevant actual or proposed 
programs, plans, reports, environmental impact statements, nominations 
information, environmental study reports, lease sale information, and 
any similar type of relevant information, including modifications, 
comments, and revisions prepared or directly obtained by the Director 
under the Act. The index shall be sent to affected States and, upon 
request, to any affected local government. The public shall be informed 
of the availability of the index.
    (b) Upon request, the Director shall transmit to affected States, 
affected local governments, and the public a copy of any information 
listed in the index which is subject to the control of BOEM, in 
accordance with the requirements and subject to the limitations of the 
Freedom of Information Act (5 U.S.C. 552) and implementing regulations. 
The Director shall not transmit or make available any information which 
he determines is exempt from disclosure in accordance with this part.

Sec.  552.6  Freedom of Information Act requirements.

    (a) The Director shall make data and information available in 
accordance with the requirements and subject to the limitations of the 
Freedom of Information Act (5 U.S.C. 552), the regulations contained in 
43 CFR part 2 (Records and Testimony), the requirements of the Act, and 
the regulations contained in 30 CFR parts 250 and 550 (Oil and Gas and 
Sulphur Operations in the Outer Continental Shelf) and 30 CFR part 551 
(Geological and Geophysical Explorations of the Outer Continental 
Shelf).
    (b) Except as provided in Sec.  552.7 or in 30 CFR parts 250, 251, 
550, and 551 of this chapter, no data or information determined by the 
director to be exempt from public disclosure under paragraph (a) of 
this section shall be provided to any affected State or be made 
available to the executive of any affected local government or to the 
public unless the lessee, or the permittee and all persons to whom such 
permittee has sold such data or information under promise of 
confidentiality, agree to such action.

Sec.  552.7  Privileged and proprietary data and information to be made 
available to affected States.

    (a)(1) The Governor of any affected State may designate an 
appropriate State official to inspect, at a regional location which the 
Director shall designate, any privileged or proprietary data or 
information received by the Director regarding any activity in an area 
adjacent to such State, except that no such inspection shall take place 
prior to the sale of a lease covering the area in which such activity 
was conducted.
    (2)(i) Except as provided for in 30 CFR 250.197, 550.197, and 
551.14, no privileged or proprietary data or information will be 
transmitted to any affected State unless the lessee who provided the 
privileged or proprietary data or information agrees in writing to the 
transmittal of the data or information.
    (ii) Except as provided for in 30 CFR 250.197, 550.197, and 551.14, 
no privileged or proprietary data or information will be transmitted to 
any affected State unless the permittee and all persons to whom the 
permittee has sold the data or information under promise of 
confidentiality agree in writing to the transmittal of the data or 
information.
    (3) Knowledge obtained by a State official who inspects data or 
information under paragraph (a)(1) of this section or who receives data 
or information under paragraph (a)(2) of this section shall be subject 
to the requirements and limitations of the Freedom of Information Act 
(5 U.S.C. 552), the regulations contained in 43 CFR part 2 (Records and 
Testimony), the Act (92 Stat. 629), the regulations contained in 30 CFR 
parts 250 and 550 (Oil and Gas and Sulphur Operations in the Outer 
Continental Shelf), the regulations contained in 30 CFR parts 251 and 
551 (Geological and Geophysical Explorations of the Outer Continental 
Shelf), and the regulations contained in 30 CFR parts 252 and 552 
(Outer Continental Shelf Oil and Gas Information Program).
    (4) Prior to the transmittal of any privileged or proprietary data 
or information to any State, or the grant of access to a State official 
to such data or information, the Secretary shall enter into a written 
agreement with the Governor of the State in accordance with section 
26(e) of the Act (43 U.S.C. 1352). In that agreement the State shall 
agree, as a condition precedent to receiving or being granted access to 
such data or information to:
    (i) Protect and maintain the confidentiality of privileged or 
proprietary data and information in accordance with the laws and 
regulations listed in paragraph (a)(3) of this section;
    (ii) Waive the defenses as set forth in paragraph (b)(2) of this 
section; and
    (iii) Hold the United States harmless from any violations of the 
agreement to protect the confidentiality of privileged or proprietary 
data or information by the State or its employees or contractors.
    (b)(1) Whenever any employee of the Federal Government or of any 
State reveals in violation of the Act or of the provisions of the 
regulations implementing the Act, privileged or proprietary data or 
information obtained pursuant to the regulations in this chapter, the 
lessee or permittee who supplied such information to the Director or 
any other Federal official, and any person to whom such lessee or 
permittee has sold such data or information under the promise of 
confidentiality, may commence a civil action for damages in the 
appropriate district court of the United States against the Federal 
Government or such State, as the case may be. Any Federal or State 
employee who is found guilty of failure to comply with any of the 
requirements of this section shall be subject to the penalties 
described in section 24 of the Act (43 U.S.C. 1350).
    (2) In any action commenced against the Federal Government or a 
State pursuant to paragraph (b)(1) of this section, the Federal 
Government or such State, as the case may be, may not raise as a 
defense any claim of sovereign immunity, or any claim that the employee 
who revealed the privileged or proprietary data or information which is 
the basis of such suit was acting outside the scope of the person's 
employment in revealing such data or information.
    (c) If the Director finds that any State cannot or does not comply 
with the conditions described in the agreement entered into pursuant to 
paragraph (a)(4) of this section, the Director shall thereafter 
withhold transmittal and

[[Page 64675]]

deny access for inspection of privileged or proprietary data or 
information to such State until the Director finds that such State can 
and will comply with those conditions.

PART 553--OIL SPILL FINANCIAL RESPONSIBILITY FOR OFFSHORE 
FACILITIES

Subpart A--General
Sec.
553.1 What is the purpose of this part?
553.3 How are the terms used in this regulation defined?
553.5 What is the authority for collecting Oil Spill Financial 
Responsibility (OSFR) information?
Subpart B--Applicability and Amount of OSFR
553.10 What facilities does this part cover?
553.11 Who must demonstrate OSFR?
553.12 May I ask BOEM for a determination of whether I must 
demonstrate OSFR?
553.13 How much OSFR must I demonstrate?
553.14 How do I determine the worst case oil-spill discharge volume?
553.15 What are my general OSFR compliance responsibilities?
Subpart C--Methods for Demonstrating OSFR
553.20 What methods may I use to demonstrate OSFR?
553.21 How can I use self-insurance as OSFR evidence?
553.22 How do I apply to use self-insurance as OSFR evidence?
553.23 What information must I submit to support my net worth 
demonstration?
553.24 When I submit audited annual financial statements to verify 
my net worth, what standards must they meet?
553.25 What financial test procedures must I use to determine the 
amount of self-insurance allowed as OSFR evidence based on net 
worth?
553.26 What information must I submit to support my unencumbered 
assets demonstration?
553.27 When I submit audited annual financial statements to verify 
my unencumbered assets, what standards must they meet?
553.28 What financial test procedures must I use to evaluate the 
amount of self-insurance allowed as OSFR evidence based on 
unencumbered assets?
553.29 How can I use insurance as OSFR evidence?
553.30 How can I use an indemnity as OSFR evidence?
553.31 How can I use a surety bond as OSFR evidence?
553.32 Are there alternative methods to demonstrate OSFR?
Subpart D--Requirements for Submitting OSFR Information
553.40 What OSFR evidence must I submit to BOEM?
553.41 What terms must I include in my OSFR evidence?
553.42 How can I amend my list of COFs?
553.43 When is my OSFR demonstration or the amendment to my OSFR 
demonstration effective?
553.44 [Reserved] 553.45 Where do I send my OSFR evidence?
Subpart E--Revocation and Penalties
553.50 How can BOEM refuse or invalidate my OSFR evidence?
553.51 What are the penalties for not complying with this part?
Subpart F--Claims for Oil-Spill Removal Costs and Damages
553.60 To whom may I present a claim?
553.61 When is a guarantor subject to direct action for claims?
553.62 What are the designated applicant's notification obligations 
regarding a claim?

Appendix to Part 553--List of U.S. Geological Survey Topographic Maps

    Authority: 33 U.S.C. 2716, 28 U.S.C. 2461.

Subpart A--General

Sec.  553.1  What is the purpose of this part?

    This part establishes the requirements for demonstrating OSFR for 
covered offshore facilities (COFs) under Title I of the Oil Pollution 
Act of 1990 (OPA), as amended, 33 U.S.C. 2701 et seq.

Sec.  553.3  How are the terms used in this regulation defined?

    Terms used in this part have the following meaning:
    Advertise means publication of the notice of designation of the 
source of the incident and the procedures by which the claims may be 
presented, according to 33 CFR part 136, subpart D.
    Bay means a body of water included in the Geographic Names 
Information System (GNIS) bay feature class. A GNIS bay includes an 
arm, bay, bight, cove, estuary, gulf, inlet, or sound.
    Claim means a written request, for a specific sum, for compensation 
for damages or removal costs resulting from an oil-spill discharge or a 
substantial threat of the discharge of oil.
    Claimant means any person or government who presents a claim for 
compensation under OPA.
    Coastline means the line of ordinary low water along that portion 
of the coast that is in direct contact with the open sea which marks 
the seaward limit of inland waters.
    Covered offshore facility (COF) means a facility:
    (1) That includes any structure and all its components (including 
wells completed at the structure and the associated pipelines), 
equipment, pipeline, or device (other than a vessel or other than a 
pipeline or deepwater port licensed under the Deepwater Port Act of 
1974 (33 U.S.C. 1501 et seq.)) used for exploring for, drilling for, or 
producing oil or for transporting oil from such facilities. This 
includes a well drilled from a mobile offshore drilling unit (MODU) and 
the associated riser and well control equipment from the moment a drill 
shaft or other device first touches the seabed for purposes of 
exploring for, drilling for, or producing oil, but it does not include 
the MODU; and
    (2) That is located:
    (i) Seaward of the coastline; or
    (ii) In any portion of a bay that is:
    (A) Connected to the sea, either directly or through one or more 
other bays; and
    (B) Depicted in whole or in part on any USGS map listed in the 
Appendix to this part, or on any map published by the USGS that is a 
successor to and covers all or part of the same area as a listed map. 
Where any portion of a bay is included on a listed map, this rule 
applies to the entire bay; and
    (3) That has a worst case oil-spill discharge potential of more 
than 1,000 bbls of oil, or a lesser volume if the Director determines 
in writing that the oil-spill discharge risk justifies the requirement 
to demonstrate OSFR.
    Designated applicant means a person the responsible parties 
designate to demonstrate OSFR for a COF on a lease, permit, or right-
of-use and easement.
    Director means the Director of the Bureau of Ocean Energy 
Management.
    Fund means the Oil Spill Liability Trust Fund established by 
section 9509 of the Internal Revenue Code of 1986 as amended (26 U.S.C. 
9509).
    Geographic Names Information System (GNIS) means the database 
developed by the USGS in cooperation with the U.S. Board of Geographic 
Names which contains the federally-recognized geographic names for all 
known places, features, and areas in the United States that are 
identified by a proper name. Each feature is located by state, county, 
and geographic coordinates and is referenced to the appropriate 
1:24,000-scale or 1:63,360-scale USGS topographic map on which it is 
shown.
    Guarantor means a person other than a responsible party who 
provides OSFR evidence for a designated applicant.
    Guaranty means any acceptable form of OSFR evidence provided by a 
guarantor including an indemnity, insurance, or surety bond.
    Incident means any occurrence or series of occurrences having the 
same origin that results in the discharge or substantial threat of the 
discharge of oil.
    Indemnity means an agreement to indemnify a designated applicant 
upon its satisfaction of a claim.

[[Page 64676]]

    Indemnitor means a person providing an indemnity for a designated 
applicant.
    Independent accountant means a certified public accountant who is 
certified by a state, or a chartered accountant certified by the 
government of jurisdiction within the country of incorporation of the 
company proposing to use one of the self-insurance evidence methods 
specified in this subpart.
    Insolvent has the meaning set forth in 11 U.S.C. 101, and generally 
refers to a financial condition in which the sum of a person's debts is 
greater than the value of the person's assets.
    Lease means any form of authorization issued under the Outer 
Continental Shelf Lands Act or state law which allows oil and gas 
exploration and production in the area covered by the authorization.
    Lessee means a person holding a leasehold interest in an oil or gas 
lease including an owner of record title or a holder of operating 
rights (working interest owner).
    Oil means oil of any kind or in any form, except as excluded by 
paragraph (2) of this definition.
    (1) Oil includes:
    (i) Petroleum, fuel oil, sludge, oil refuse, and oil mixed with 
wastes other than dredged spoil;
    (ii) Hydrocarbons produced at the wellhead in liquid form;
    (iii) Gas condensate that has been separated from gas before 
pipeline injection.
    (2) Oil does not include petroleum, including crude oil or any 
fraction thereof, which is specifically listed or designated as a 
hazardous substance under subparagraphs (A) through (F) of section 
101(14) of the Comprehensive Environmental Response, Compensation, and 
Liability Act (CERCLA) (42 U.S.C. 9601).
    Oil Spill Financial Responsibility (OSFR) means the capability and 
means by which a responsible party for a covered offshore facility will 
meet removal costs and damages for which it is liable under Title I of 
the Oil Pollution Act of 1990, as amended (33 CFR 2701 et seq.), with 
respect to both oil-spill discharges and substantial threats of the 
discharge of oil.
    Outer Continental Shelf (OCS) has the same meaning as the term 
``Outer Continental Shelf'' defined in section 2(a) of the OCS Lands 
Act (OCSLA) (43 U.S.C. 1331(a)).
    Permit means an authorization, license, or permit for geological 
exploration issued under section 11 of the OCSLA (43 U.S.C. 1340) or 
applicable state law.
    Person means an individual, corporation, partnership, association 
(including a trust or limited liability company), state, municipality, 
commission or political subdivision of a state, or any interstate body.
    Pipeline means the pipeline segments and any associated equipment 
or appurtenances used or intended for use in the transportation of oil 
or natural gas.
    Responsible party has the following meanings:
    (1) For a COF that is a pipeline, responsible party means any 
person owning or operating the pipeline;
    (2) For a COF that is not a pipeline, responsible party means 
either the lessee or permittee of the area in which the COF is located, 
or the holder of a right-of-use and easement granted under applicable 
state law or the OCSLA (43 U.S.C. 1301-1356) for the area in which the 
COF is located (if the holder is a different person than the lessee or 
permittee). A Federal agency, State, municipality, commission, or 
political subdivision of a state, or any interstate body that as owner 
transfers possession and right to use the property to another person by 
lease, assignment, or permit is not a responsible party; and
    (3) For an abandoned COF, responsible party means any person who 
would have been a responsible party for the COF immediately before 
abandonment.
    Right-of-use and easement (RUE) means any authorization to use the 
OCS or submerged land for purposes other than those authorized by a 
lease or permit, as defined herein. It includes pipeline rights-of-way.
    Source of the incident means the facility from which oil was 
discharged or which poses a substantial threat of discharging oil, as 
designated by the Director, National Pollution Funds Center, according 
to 33 CFR part 136, subpart D.
    State means the several States of the United States, the District 
of Columbia, the Commonwealth of Puerto Rico, Guam, American Samoa, the 
United States Virgin Islands, the Commonwealth of the Northern 
Marianas, and any other territory or possession of the United States.

Sec.  553.5  What is the authority for collecting Oil Spill Financial 
Responsibility (OSFR) information?

    (a) The Office of Management and Budget (OMB) has approved the 
information collection requirements in this part 553 under 44 U.S.C. 
3501 et seq., and assigned OMB control number 1010-0106.
    (b) BOEM collects the information to ensure that the designated 
applicant for a COF has the financial resources necessary to pay for 
cleanup and damages that could be caused by oil discharges from the 
COF. BOEM uses the information to ensure compliance of offshore 
lessees, owners, and operators of covered facilities with OPA; to 
establish eligibility of designated applicants for OSFR certification 
(OSFRC); and to establish a reference source of names, addresses, and 
telephone numbers of responsible parties for covered facilities and 
their designated agents, guarantors, and U.S. agents for service of 
process for claims associated with oil pollution from designated 
covered facilities. The requirement to provide the information is 
mandatory. No information submitted for OSFRC is confidential or 
proprietary.
    (c) An agency may not conduct or sponsor, and a person is not 
required to respond to, a collection of information unless it displays 
a currently valid OMB control number.
    (d) Send comments regarding any aspect of the collection of 
information under this part, including suggestions for reducing the 
burden, to the Information Collection Clearance Officer, Bureau of 
Ocean Energy Management, 381 Elden Street, Herndon, VA 20170.

Subpart B--Applicability and Amount of OSFR

Sec.  553.10  What facilities does this part cover?

    (a) This part applies to any COF on any lease or permit issued or 
on any RUE granted under the OCSLA or applicable State law.
    (b) For a pipeline COF that extends onto land, this part applies to 
that portion of the pipeline lying seaward of the first accessible flow 
shut-off device on land.

Sec.  553.11  Who must demonstrate OSFR?

    (a) A designated applicant must demonstrate OSFR. A designated 
applicant may be a responsible party or another person authorized under 
this section. Each COF must have a single designated applicant.
    (1) If there is more than one responsible party, those responsible 
parties must use Form BOEM-1017 to select a designated applicant. The 
designated applicant must submit Form BOEM-1016 and agree to 
demonstrate OSFR on behalf of all the responsible parties.
    (2) If you are a designated applicant who is not a responsible 
party, you must agree to be liable for claims made under OPA jointly 
and severally with the responsible parties.

[[Page 64677]]

    (b) The designated applicant for a COF on a lease must be either:
    (1) A lessee; or
    (2) The designated operator for the OCS lease under 30 CFR 550.143 
or the unit operator designated under a Federally approved unit 
including the OCS lease. For a lease or unit not in the OCS, the 
operator designated under the lease or unit operating agreement for the 
lease may be the designated applicant only if the operator has agreed 
to be responsible for compliance with all the laws and regulations 
applicable to the lease or unit.
    (c) The designated applicant for a COF on a permit must be the 
permittee.
    (d) The designated applicant for a COF on a RUE must be the holder 
of the RUE or, if there is a pipeline on the RUE, the owner or operator 
of the pipeline.
    (e) BOEM may require the designated applicant for a lease, permit, 
or RUE to be a person other than a person identified in paragraphs (b) 
through (d) of this section if BOEM determines that a person identified 
in paragraphs (b) through (d) cannot adequately demonstrate OSFR.
    (f) If you are a responsible party and you fail to designate an 
applicant, then you must demonstrate OSFR under the requirements of 
this part.

Sec.  553.12  May I ask BOEM for a determination of whether I must 
demonstrate OSFR?

    You may submit to BOEM a request for a determination of OSFR 
applicability. Address the request to the office identified in Sec.  
553.45. You must include in your request any information that will 
assist BOEM in making the determination. BOEM may require you to submit 
other information before making a determination of OSFR applicability.

Sec.  553.13  How much OSFR must I demonstrate?

    (a) The following general parameters apply to the amount of OSFR 
that you must demonstrate:

------------------------------------------------------------------------
 If you are the designated applicant for .   Then you must demonstrate .
                    . .                                  . .
------------------------------------------------------------------------
Only one COF,                               The amount of OSFR that
                                             applies to the COF.
More than one COF,                          The highest amount of OSFR
                                             that applies to any one of
                                             the COFs.
------------------------------------------------------------------------

     (b) You must demonstrate OSFR in the amounts specified in this 
section:
    (1) For a COF located wholly or partially in the OCS you must 
demonstrate OSFR in accordance with the following table:

------------------------------------------------------------------------
                                                            Applicable
        COF worst case oil-spill discharge volume         amount of OSFR
------------------------------------------------------------------------
Over 1,000 bbls but not more than 35,000 bbls...........     $35,000,000
Over 35,000 but not more than 70,000 bbls...............      70,000,000
Over 70,000 but not more than 105,000 bbls..............     105,000,000
Over 105,000 bbls.......................................     150,000,000
------------------------------------------------------------------------

     (2) For a COF not located in the OCS you must demonstrate OSFR in 
accordance with the following table:

------------------------------------------------------------------------
                                                            Applicable
        COF worst case oil-spill discharge volume         amount of OSFR
------------------------------------------------------------------------
Over 1,000 bbls but not more than 10,000 bbls...........     $10,000,000
Over 10,000 but not more than 35,000 bbls...............      35,000,000
Over 35,000 but not more than 70,000 bbls...............      70,000,000
Over 70,000 but not more than 105,000 bbls..............     105,000,000
Over 105,000 bbls.......................................     150,000,000
------------------------------------------------------------------------

    (3) The Director may determine that you must demonstrate an amount 
of OSFR greater than the amount in paragraphs (b)(1) and (2) of this 
section based on the relative operational, environmental, human health, 
and other risks that your COF poses. The Director may require an amount 
that is one or more levels higher than the amount indicated in 
paragraph (b)(1) or (2) of this section for your COF. The Director will 
not require an OSFR demonstration that exceeds $150 million.
    (4) You must demonstrate OSFR in the lowest amount specified in the 
applicable table in paragraph (b)(1) or (2) of this section for a 
facility with a potential worst case oil-spill discharge of 1,000 bbls 
or less if the Director notifies you in writing that the demonstration 
is justified by the risks of the potential oil-spill discharge.

Sec.  553.14  How do I determine the worst case oil-spill discharge 
volume?

    (a) To calculate the amount of OSFR you must demonstrate for a 
facility under Sec.  553.13(b), you must use the worst case oil-spill 
discharge volume that you determined under whichever of the following 
regulations applies:
    (1) 30 CFR part 254--Response Plans for Facilities Located Seaward 
of the Coast Line, except that the volume of the worst case oil-spill 
discharge for a well must be four times the uncontrolled flow volume 
that you estimate for the first 24 hours.
    (2) 40 CFR part 112--Oil Pollution Prevention; or
    (3) 49 CFR part 194--Response Plans for Onshore Oil Pipelines.
    (b) If you are a designated applicant and you choose to demonstrate 
$150 million in OSFR, you are not required to determine any worst case 
oil-spill discharge volumes, since that is the maximum amount of OSFR 
required under this part.

[[Page 64678]]

Sec.  553.15  What are my general OSFR compliance responsibilities?

    (a) You must maintain continuous OSFR coverage for all your leases, 
permits, and RUEs with COFs for which you are the designated applicant.
    (b) You must ensure that new OSFR evidence is submitted before your 
current evidence lapses or is canceled and that coverage for your new 
COF is submitted before the COF goes into operation.
    (c) If you use self-insurance to demonstrate OSFR and find that you 
no longer qualify to self-insure the required OSFR amount based upon 
your latest audited annual financial statements, then you must 
demonstrate OSFR using other methods acceptable to BOEM by whichever of 
the following dates comes first:
    (1) Sixty calendar days after you receive your latest audited 
annual financial statement; or
    (2) The first calendar day of the 5th month after the close of your 
fiscal year.
    (d) You may use a surety bond to demonstrate OSFR. If you find that 
your bonding company has lost its state license or has had its U.S. 
Treasury Department certification revoked, then you must replace the 
surety bond within 15 calendar days using a method of OSFR that is 
acceptable to BOEM.
    (e) You must notify BOEM in writing within 15 calendar days after a 
change occurs that would prevent you from meeting your OSFR obligations 
(e.g., if you or your indemnitor petition for bankruptcy under chapters 
7 or 11 of Title 11, U.S.C.). You must take any action BOEM directs to 
ensure an acceptable OSFR demonstration.
    (f) If you deny payment of a claim presented to you under Sec.  
553.60, then you must give the claimant a written explanation for your 
denial.

Subpart C--Methods for Demonstrating OSFR

Sec.  553.20  What methods may I use to demonstrate OSFR?

    As the designated applicant, you may satisfy your OSFR requirements 
by using one or a combination of the following methods to demonstrate 
OSFR:
    (a) Self-insurance under Sec. Sec.  553.21 through 553.28;
    (b) Insurance under Sec.  553.29;
    (c) An indemnity under Sec.  553.30;
    (d) A surety bond under Sec.  553.31; or
    (e) An alternative method the Director approves under Sec.  553.32.

Sec.  553.21  How can I use self-insurance as OSFR evidence?

    (a) If you use self-insurance to satisfy all or part of your 
obligation to demonstrate OSFR, you must annually pass either a net 
worth test under Sec.  553.25 or an unencumbered net asset test under 
Sec.  553.28.
    (b) To establish the amount of self-insurance allowed, you must 
submit evidence of your net worth under Sec.  553.23 or evidence of 
your unencumbered assets under Sec.  553.26.
    (c) You must identify a U.S. agent for service of process.

Sec.  553.22  How do I apply to use self-insurance as OSFR evidence?

    (a) You must submit a complete Form BOEM-1018 with each application 
to demonstrate OSFR using self-insurance.
    (b) You must submit your application to renew OSFR using self-
insurance by the first calendar day of the 5th month after the close of 
your fiscal year. You may submit to BOEM your initial application to 
demonstrate OSFR using self-insurance at any time.

Sec.  553.23  What information must I submit to support my net worth 
demonstration?

    You must support your net worth evaluation with information 
contained in your previous fiscal year's audited annual financial 
statement.
    (a) Audited annual financial statements must be in the form of:
    (1) An annual report, prepared in accordance with the generally 
accepted accounting practices (GAAP) of the United States or other 
international accounting practices determined to be equivalent by BOEM; 
or
    (2) A Form 10-K or Form 20-F, prepared in accordance with 
Securities and Exchange Commission regulations.
    (b) Audited annual financial statements must be submitted together 
with a letter signed by your treasurer highlighting:
    (1) The State or the country of incorporation;
    (2) The total amount of the stockholders' equity as shown on the 
balance sheet;
    (3) The net amount of the plant, property, and equipment shown on 
the balance sheet; and
    (4) The net amount of the identifiable U.S. assets and the 
identifiable total assets in the auditor's notes to the financial 
statement (i.e., a geographic segmented business note).

Sec.  553.24  When I submit audited annual financial statements to 
verify my net worth, what standards must they meet?

    (a) Your audited annual financial statements must be bound.
    (b) Your audited annual financial statements must include the 
unqualified opinion of an independent accountant that states:
    (1) The financial statements are free from material misstatement, 
and
    (2) The audit was conducted in accordance with the generally 
accepted auditing standards (GAAS) of the United States, or other 
international auditing standards that BOEM determines to be equivalent.
    (c) The financial information you submit must be expressed in U.S. 
dollars. If this information was originally reported in another form of 
currency, you must convert it to U.S. dollars using the conversion 
factor that was effective on the last day of the fiscal year pertinent 
to your financial statements. You also must identify the source of the 
currency exchange rate.

Sec.  553.25  What financial test procedures must I use to determine 
the amount of self-insurance allowed as OSFR evidence based on net 
worth?

    (a) Divide the total amount of the stockholders'/owners' equity 
listed on the balance sheet by ten.
    (b) Divide the net amount of the identifiable U.S. assets by the 
net amount of the identifiable total assets.
    (c) Multiply the net amount of plant, property, and equipment shown 
on the balance sheet by the number calculated under paragraph (b) of 
this section and divide the resultant product by ten.
    (d) The smaller of the numbers calculated under paragraphs (a) or 
(c) of this section is the maximum allowable amount you may use to 
demonstrate OSFR under this method.

Sec.  553.26  What information must I submit to support my unencumbered 
assets demonstration?

    You must support your unencumbered assets evaluation with the 
information required by Sec.  553.23(a) and a list of reserved, 
unencumbered, and unimpaired U.S. assets whose value will not be 
affected by an oil discharge from a COF. The assets must be plant, 
property, or equipment held for use. You must submit a letter signed by 
your treasurer:
    (a) Identifying which assets are reserved;
    (b) Certifying that the assets are unencumbered, including 
contingent encumbrances;
    (c) Promising that the identified assets will not be sold, 
subjected to a security interest, or otherwise encumbered throughout 
the specified fiscal year; and
    (d) Specifying:
    (1) The State or the country of incorporation;
    (2) The total amount of the stockholders'/owners' equity listed on 
the balance sheet;
    (3) The identification and location of the reserved U.S. assets; 
and
    (4) The value of the reserved U.S. assets less accumulated 
depreciation

[[Page 64679]]

and amortization, using the same valuation method used in your audited 
annual financial statement and expressed in U.S. dollars. The net value 
of the reserved assets must be at least two times the self-insurance 
amount requested for demonstration.

Sec.  553.27  When I submit audited annual financial statements to 
verify my unencumbered assets, what standards must they meet?

    Any audited annual financial statements that you submit must:
    (a) Meet the standards in Sec.  553.24; and
    (b) Include a certification by the independent accountant who 
audited the financial statements that states:
    (1) The value of the unencumbered assets is reasonable and uses the 
same valuation method used in your audited annual financial statements;
    (2) Any existing encumbrances are noted;
    (3) The assets are long-term assets held for use; and
    (4) The valuation method used in the audited annual financial 
statements is for long-term assets held for use.

Sec.  553.28  What financial test procedures must I use to evaluate the 
amount of self-insurance allowed as OSFR evidence based on unencumbered 
assets?

    (a) Divide the total amount of the stockholders'/owners' equity 
listed on the balance sheet by 4.
    (b) Divide the value of the unencumbered U.S. assets by 2.
    (c) The smaller number calculated under paragraphs (a) or (b) of 
this section is the maximum allowable amount you may use to demonstrate 
OSFR under this method.

Sec.  553.29  How can I use insurance as OSFR evidence?

    (a) If you use insurance to satisfy all or part of your obligation 
to demonstrate OSFR, you may use only insurance certificates issued by 
insurers that have achieved a ``Secure'' rating for claims paying 
ability in their latest review by A.M. Best's Insurance Reports, 
Standard & Poor's Insurance Rating Services, or other equivalent rating 
made by a rating service acceptable to BOEM.
    (b) You must submit information about your insurers to BOEM on a 
completed and unaltered Form BOEM-1019. The information you submit 
must:
    (1) Include all the information required by Sec.  553.41 and
    (2) Be executed on one original insurance certificate (i.e., Form 
BOEM-1019) for each OSFR layer (see paragraph (c) of this section), 
showing all participating insurers and their proportion (quota share) 
of this risk. The certificate must bear the original signatures of each 
insurer's underwriter or of their lead underwriters, underwriting 
managers, or delegated brokers, depending on who is authorized to bind 
the underwriter.
    (3) For each insurance company on the insurance certificate, 
indicate the insurer's claims-paying-ability rating and the rating 
service that issued the rating.
    (c) The insurance evidence you provide to BOEM as OSFR evidence may 
be divided into layers, subject to the following restrictions:
    (1) The total amount of OSFR evidence must equal the total amount 
you must demonstrate under Sec.  553.13;
    (2) No more than one insurance certificate may be used to cover 
each OSFR layer specified in Sec.  553.13(b) (i.e., four layers for an 
OCS COF, and five layers for a non-OCS COF);
    (3) You may use one insurance certificate to cover any number of 
consecutive OSFR layers;
    (4) Each insurer's participation in the covered insurance risk must 
be on a proportional (quota share) basis, must be expressed as a 
percentage of a whole layer, and the certificate must not contain 
intermediate, horizontal layers;
    (5) You may use an insurance deductible. If you use more than one 
insurance certificate, the deductible amount must apply only to the 
certificate that covers the base OSFR amount layer. To satisfy an 
insurance deductible, you may use only those methods that are 
acceptable as evidence of OSFR under this part; and
    (6) You must identify a U.S. agent for service of process on each 
insurance certificate you submit to BOEM. The agent may be different 
for each insurance certificate.
    (d) You may submit to BOEM a temporary insurance confirmation (fax 
binder) for each insurance certificate you use as OSFR evidence. Submit 
your fax binder on Form BOEM-1019, and each form must include the 
signature of an underwriter for at least one of the participating 
insurers. BOEM will accept your fax binder as OSFR evidence during a 
period that ends 90 days after the date that you need the insurance to 
demonstrate OSFR.

Sec.  553.30  How can I use an indemnity as OSFR evidence?

    (a) You may use only one indemnity issued by only one indemnitor to 
satisfy all or part of your obligation to demonstrate OSFR.
    (b) Your indemnitor must be your corporate parent or affiliate.
    (c) Your indemnitor must complete a Form BOEM-1018 and provide an 
indemnity that:
    (1) Includes all the information required by Sec.  553.41; and
    (2) Does not exceed the amounts calculated using the net worth or 
unencumbered assets tests specified under Sec. Sec.  553.21 through 
553.28.
    (d) You must submit your application to renew OSFR using an 
indemnity by the first calendar day of the 5th month after the close of 
your indemnitor's fiscal year. You may submit to BOEM your initial 
application to demonstrate OSFR using an indemnity at any time.
    (e) Your indemnitor must identify a U.S. agent for service of 
process.

Sec.  553.31  How can I use a surety bond as OSFR evidence?

    (a) Each bonding company that issues a surety bond that you submit 
to BOEM as OSFR evidence must:
    (1) Be licensed to do business in the State in which the surety 
bond is executed;
    (2) Be certified by the U.S. Treasury Department as an acceptable 
surety for Federal obligations and listed in the current Treasury 
Circular No. 570;
    (3) Provide the surety bond on Form BOEM-1020; and
    (4) Be in compliance with applicable statutes regulating surety 
company participation in insurance-type risks.
    (b) A surety bond that you submit as OSFR evidence must include all 
the information required by Sec.  553.41.

Sec.  553.32  Are there alternative methods to demonstrate OSFR?

    The Director may accept other methods to demonstrate OSFR that 
provide equivalent assurance of timely satisfaction of claims. This may 
include pooling, letters of credit, pledges of treasury notes, or other 
comparable methods. Submit your proposal, together with all the 
supporting documents, to the Director at the address listed in Sec.  
553.45. The Director's decision whether to approve your alternative 
method to evidence OSFR is by this rule committed to the Director's 
sole discretion and is not subject to administrative appeal under 30 
CFR part 590 or 43 CFR part 4.

Subpart D--Requirements for Submitting OSFR Information

Sec.  553.40  What OSFR evidence must I submit to BOEM?

    (a) You must submit to BOEM:
    (1) A single demonstration of OSFR that covers all the COFs for 
which you are the designated applicant;
    (2) A completed and unaltered Form BOEM-1016;
    (3) BOEM forms that identify your COFs (Form BOEM-1021, Form BOEM-
1022), and the methods you will use to

[[Page 64680]]

demonstrate OSFR (Form BOEM-1018, Form BOEM-1019, Form BOEM-1020). 
Forms are available from the address listed in Sec.  553.45;
    (4) Any insurance certificates, indemnities, and surety bonds used 
as OSFR evidence for the COFs for which you are the designated 
applicant;
    (5) A completed Form BOEM-1017 for each responsible party, unless 
you are the only responsible party for the COFs covered by your OSFR 
demonstration; and
    (6) Other financial instruments and information the Director 
requires to support your OSFR demonstration under Sec.  553.32.
    (b) Each BOEM form you submit to BOEM as part of your OSFR 
demonstration must be signed. You also must attach to Form BOEM-1016 
proof of your authority to sign.

Sec.  553.41  What terms must I include in my OSFR evidence?

    (a) Each instrument you submit as OSFR evidence must specify:
    (1) The effective date, and except for a surety bond, the 
expiration date;
    (2) That termination of the instrument will not affect the 
liability of the instrument issuer for claims arising from an incident 
(i.e., oil-spill discharge or substantial threat of the discharge of 
oil) that occurred on or before the effective date of termination;
    (3) That the instrument will remain in force until the termination 
date or until the earlier of:
    (i) Thirty calendar days after BOEM and the designated applicant 
receive from the instrument issuer a notification of intent to cancel; 
or
    (ii) BOEM receives from the designated applicant other acceptable 
OSFR evidence; or
    (iii) All the COFs to which the instrument applies are permanently 
abandoned in compliance with 30 CFR part 250 or equivalent State 
requirements;
    (4) That the instrument issuer agrees to direct action for claims 
made under OPA up to the guaranty amount, subject to the defenses in 
paragraph (a)(6) of this section and following the procedures in Sec.  
553.60 of this part;
    (5) An agent in the United States for service of process; and
    (6) That the instrument issuer will not use any defenses against a 
claim made under OPA except:
    (i) The rights and defenses that would be available to a designated 
applicant or responsible party for whom the guaranty was provided; and
    (ii) The incident (i.e., oil-spill discharge or a substantial 
threat of the discharge of oil) leading to the claim for removal costs 
or damages was caused by willful misconduct of a responsible party for 
whom the designated applicant demonstrated OSFR.
    (b) You may not change, omit, or add limitations or exceptions to 
the terms and conditions in a BOEM form that you submit as part of your 
OSFR demonstration. If you attempt to do this, BOEM will disregard the 
changes, omissions, additions, limitations, or exceptions and by 
operation of this rule BOEM will consider the form to contain all the 
terms and conditions included on the original BOEM form.

Sec.  553.42  How can I amend my list of COFs?

    (a) If you want to add a COF that is not identified in your current 
OSFR demonstration, you must submit to BOEM a completed Form BOEM-1022. 
If applicable, you also must submit any additional indemnities, surety 
bonds, insurance certificates, or other instruments required to extend 
the coverage of your original OSFR demonstration to the COFs to be 
added. You do not need to resubmit previously accepted audited annual 
financial statements for the current fiscal year.
    (b) If you want to drop a COF identified in your current OSFR 
demonstration, you must submit to BOEM a completed Form BOEM-1022. You 
must continue to demonstrate OSFR for the COF until BOEM approves OSFR 
evidence for the COF from another designated applicant, or OSFR is no 
longer required (e.g., until a well that is a COF is properly plugged 
and abandoned).

Sec.  553.43  When is my OSFR demonstration or the amendment to my OSFR 
demonstration effective?

    (a) BOEM will notify you in writing when we approve your OSFR 
demonstration. If we find that you have not submitted all the 
information needed to demonstrate OSFR, we may require you to provide 
additional information before we determine whether your OSFR evidence 
is acceptable.
    (b) Except in the case of self-insurance or an indemnity, BOEM 
acceptance of OSFR evidence is valid until the surety bond, insurance 
certificate, or other accepted OSFR instrument expires or is canceled. 
In the case of self-insurance or indemnity, acceptance is valid until 
the first day of the 5th month after the close of your or your 
indemnitor's current fiscal year.

Sec.  553.44  [Reserved]

Sec.  553.45  Where do I send my OSFR evidence?

    Address all correspondence and required submissions related to this 
part to: U.S. Department of the Interior, Bureau of Ocean Energy 
Management, Gulf of Mexico Region, Oil Spill Financial Responsibility 
Program, 1201 Elmwood Park Boulevard, New Orleans, Louisiana 70123.

Subpart E--Revocation and Penalties

Sec.  553.50  How can BOEM refuse or invalidate my OSFR evidence?

    (a) If BOEM determines that any OSFR evidence you submit fails to 
comply with the requirements of this part, we may not accept it. If we 
do not accept your OSFR evidence, then we will send you a written 
notification stating:
    (1) That your evidence is not acceptable;
    (2) Why your evidence is unacceptable; and
    (3) The amount of time you are allowed to submit acceptable 
evidence without being subject to civil penalty under Sec.  553.51.
    (b) BOEM may immediately and without prior notice invalidate your 
OSFR demonstration if you:
    (1) Are no longer eligible to be the designated applicant for a COF 
included in your demonstration; or
    (2) Permit the cancellation or termination of the insurance policy, 
surety bond, or indemnity upon which the continued validity of the 
demonstration is based.
    (c) If BOEM determines you are not complying with the requirements 
of this part for any reason other than paragraph (b) of this section, 
we will notify you of our intent to invalidate your OSFR demonstration 
and specify the corrective action needed. Unless you take the 
corrective action BOEM specifies within 15 calendar days from the date 
you receive such a notice, we will invalidate your OSFR demonstration.

Sec.  553.51  What are the penalties for not complying with this part?

    (a) If you fail to comply with the financial responsibility 
requirements of OPA at 33 U.S.C. 2716 or with the requirements of this 
part, then you may be liable for a civil penalty of up to $30,000 per 
COF per day of violation (that is, each day a COF is operated without 
acceptable evidence of OSFR).
    (b) BOEM will determine the date of a noncompliance. BOEM will 
assess penalties in accordance with an OSFR penalty schedule using the 
procedures

[[Page 64681]]

found at 30 CFR part 550, subpart N. You may obtain a copy of the 
penalty schedule from BOEM at the address in Sec.  553.45.
    (c) BOEM may assess a civil penalty against you that is greater or 
less than the amount in the penalty schedule after taking into account 
the factors in section 4303(a) of OPA (33 U.S.C. 2716a).
    (d) If you fail to correct a deficiency in the OSFR evidence for a 
COF, then the Director may suspend operation of a COF in the OCS under 
30 CFR 250.170 or seek judicial relief, including an order suspending 
the operation of any COF.

Subpart F--Claims for Oil-Spill Removal Costs and Damages

Sec.  553.60  To whom may I present a claim?

    (a) If you are a claimant, you must present your claim first to the 
designated applicant for the COF that is the source of the incident 
resulting in your claim. If, however, the designated applicant has 
filed a petition for bankruptcy under 11 U.S.C. chapter 7 or 11, you 
may present your claim first to any of the designated applicant's 
guarantors.
    (b) If the claim you present to the designated applicant or 
guarantor is denied or not paid within 90 days after you first present 
it or advertising begins, whichever is later, then you may seek any of 
the following remedies that apply:

------------------------------------------------------------------------
 If the reason for denial or nonpayment is
                   . . .                     Then you may elect to . . .
------------------------------------------------------------------------
(1) Not an assertion of insolvency or       (i) Present your claim to
 petition in bankruptcy under 11 U.S.C.      any of the responsible
 chapter 7 or 11,                            parties for the COF; or
                                            (ii) Initiate a lawsuit
                                             against the designated
                                             applicant and/or any of the
                                             responsible parties for the
                                             COF; or
                                            (iii) Present your claim to
                                             the Fund using the
                                             procedures at 33 CFR part
                                             136.
(2) An assertion of insolvency or petition  (i) Pursue any of the
 in bankruptcy under 11 U.S.C. chapter 7     remedies in items (1)(i)
 or 11,                                      through (iii) of this
                                             table; or
                                            (ii) Present your claim to
                                             any of the designated
                                             applicant's guarantors; or
                                            (iii) Initiate a lawsuit
                                             against any of the
                                             designated applicant's
                                             guarantors.
------------------------------------------------------------------------

     (c) If no one has resolved your claim to your satisfaction using 
the remedy that you elected under paragraph (b) of this section, then 
you may pursue another available remedy, unless the Fund has denied 
your claim or a court of competent jurisdiction has ruled against your 
claim. You may not pursue more than one remedy at a time.
    (d) You may ask BOEM to assist you in determining whether a 
guarantor may be liable for your claim. Send your request for 
assistance to the address listed in Sec.  553.45. You must include any 
information you have regarding the existence or identity of possible 
guarantors.

Sec.  553.61  When is a guarantor subject to direct action for claims?

    (a) If you are a guarantor, then you are subject to direct action 
for any claim asserted by:
    (1) The United States for any compensation paid by the Fund under 
OPA, including compensation claim processing costs; and
    (2) A claimant other than the United States if the designated 
applicant has:
    (i) Denied or failed to pay a claim because of being insolvent; or
    (ii) Filed a petition in bankruptcy under 11 U.S.C. chapters 7 or 
11.
    (b) If you participate in an insurance guaranty for a COF incident 
(i.e., oil-spill discharge or substantial threat of the discharge of 
oil) that is subject to claims under this part, then your maximum, 
aggregate liability for those claims is equal to your quota share of 
the insurance guaranty.

Sec.  553.62  What are the designated applicant's notification 
obligations regarding a claim?

    If you are a designated applicant, and you receive a claim for 
removal costs and damages, then within 15 calendar days of receipt of a 
claim you must notify:
    (a) Your guarantors; and
    (b) The responsible parties for whom you are acting as the 
designated applicant.

Appendix to Part 553--List of U.S. Geological Survey Topographic Maps

    Alabama (1:24,000 scale): Bellefontaine; Bon Secour Bay; 
Bridgehead; Coden; Daphne; Fort Morgan; Fort Morgan NW; Grand Bay; 
Grand Bay SW; Gulf Shores; Heron Bay; Hollingers Island; Isle Aux 
Herbes; Kreole; Lillian; Little Dauphin Island; Little Point Clear; 
Magnolia Springs; Mobile; Orange Beach; Perdido Beach; Petit Bois 
Island; Petit Bois Pass; Pine Beach; Point Clear; Saint Andrews Bay; 
West Pensacola.
    Alaska (1:63,360 scale): Afognak (A-1, A-2, A-3, A-4, A-5, A-
0&B-0, B-1, B-2, B-3, C-1&2, C-2&3, C-5, C-6, D-1, D-4, D-5); 
Anchorage (A-1, A-2, A-3, A-4, A-8, B-7, B-8); Barrow (A-1, A-2, A-
3, A-4, A-5, B-3, B-4); Baird Mts. (A-6); Barter Island (A-3, A-4, 
A-5); Beechy Point (A-1, A-2, B-1, B-2, B-3, B-4, B-5, C-4, C-5); 
Bering Glacier (A-1, A-2, A-3, A-4, A-5, A-6, A-7, A-8); Black (A-1, 
A-2, B-1, C-1); Blying Sound (C-7, C-8, D-1&2, D-3, D-4, D-5, D-6, 
D-7, D-8); Candle (D-6); Cordova (A-1, A-2, A-3, A-4, A-7&8, B-2, B-
3, B-4, B-5, B-6, B-7, B-8, C-5, C-6, C-7, C-8, D-6, D-7, D-8); De 
Long Mts. (D-4, D-5); Demarcation Point (C-1, C-2, D-2, D-3); 
Flaxman Island (A-1, A-3, A-4, A-5, B-5); Harrison Bay (B-1, B-2, B-
3, B-4, C-1, C-3, C-4, C-5, D-4, D-5); Icy Bay (D1, D-2&3); Iliamna 
(A-2, A-3, A-4, B-2, B-3, C-1, C-2, D-1); Karluk (A-1, A-2, B-2, B-
3, C-1, C-2, C-4&5, C-6); Kenai (A-4, A-5, A-7, A-8, B-4, B-6, B-7, 
B-8, C-4, C-5, C-6, C-7, D-1, D-2, D-3, D-4, D-5); Kodiak (A-3, A-4, 
A-5, A-6, B-1&2, B-3, B-4, B-6, C-1, C-2, C-3, C-5, C-6, D-1, D-2, 
D-3, D-4, D-5, D-6); Kotzebue (A-1, A-2, A-3, A-4, B-4, B-6, C-1, C-
4, C-5, C-6, D-1, D-2); Kwiguk (C-6, D-6); Meade River (D-1, D-3, D-
4, D-5); Middleton Island (B-7, D-1&2); Mt. Katmai (A-1, A-2, A-3; 
B-1); Mt. Michelson (D-1, D-2, D-3); Mt. St. Elias (A-5); Noatak (A-
1, A-2, A-3, A-4, B-4, C-4, C-5, D-6, D-7); Nome (B-1, C-1, C-2, C-
3, D-3, D-4, D-7); Norton Bay (A-4, B-4, B-5, B-6, C-4, C-5, C-6, D-
4, D-5, D-6); Point Hope (A-1, A-2, B-2, B-3, C-2, C-3, D-1, D-2); 
Point Lay (A-3&4, B-2&3, C-2, D-1, D-2); Selawik (A-5, A-6, B-5, B-
6, C-5, C-6, D-6); Seldovia (A-3, A-4, A-5, A-6, B-1, B-2, B-3, B-4, 
B-5, B-6, C-1, C-2, C-3, C-4, C-5, D-1, D-3, D-4, D-5, D-8); Seward 
(A-1, A-2, A-3, A-4, A-5, A-6, A-7, B-1, B-2, B-3, B-4, B-5, C-1, C-
2, C-3, C-4, C-5, D-1, D-2, D-3, D-4, D-5, D-6, D-7, D-8); 
Shishmaref (A-2, A-3, A-4, B-1, B-2, B-3); Solomon (B-2, B-3, B-6, 
C-1, C-2, C-3, C-4, C-5, C-6); St. Michael (A-2, A-3, A-4, A-5, A-6, 
B-1, B-2, C-1, C-2); Teller (A-2, A-3, A-4, B-3, B-4, B-5, B-6, C-6, 
C-7, D-4, D-5, D-6, D-8); Teshekpuk (D-1, D-2, D-3, D-4, D-5); 
Tyonek (A-1, A-2, A-3, A-4, B-1, B-2); Unalakleet (B-5, B-6, C-4, C-
5, D-4); Valdez (A-7, A-8); Wainwright (A-5, A-6&7, B-2, B-3, B-4, 
B-5&6, C-2, C-3, D-1, D-2; Yakutat (A-1, A-2, A-2, B-3, B-4, B-5, C-
4, C-5, C-6, C-7, C-8, D-3, D-4, D-5, D-6, D-8).
    California (1:24,000 scale): Arroyo Grande NE; Beverly Hills; 
Carpinteria; Casmalia; Dana Point; Del Mar; Dos Pueblos Canyon; 
Encinitas; Gaviota; Goleta; Guadalupe; Imperial Beach; Laguna Beach; 
La Jolla; Las Pulgas Canyon; Lompoc Hills; Long Beach; Los Alamitos; 
Malibu Beach; Morro Bay

[[Page 64682]]

South; National City; Newport Beach; Oceano; Oceanside; Oxnard; 
Pismo Beach; Pitas Point; Point Arguello; Point Conception; Point 
Dune; Point Loma; Point Mugu; Point Sal; Port San Luis; Rancho Santa 
Fe; Redondo Beach; Sacate; San Clemente; San Juan Capistrano; San 
Luis Rey; San Onofre Bluff; San Pedro; Santa Barbara; Saticoy; Seal 
Beach; Surf; Tajiguas; Topanga; Torrance; Tranquillon Mountain; 
Triunfo Pass; Tustin; Venice; Ventura; White Ledge Peak.
    Florida (1:24,000 scale): Allanton; Alligator Bay; Anna Maria; 
Apalachicola; Aripeka; Bayport; Beacon Beach; Beacon Hill; Bee 
Ridge; Belle Meade; Belle Meade NW; Beverly; Big Lostmans Bay; Bird 
Keys; Bokeelia; Bonita Springs; Bradenton; Bradenton Beach; Bruce; 
Bunker; Cape Romano; Cape Saint George; Cape San Blas; Captiva; 
Carrabelle; Cedar Key; Chassahowitzka; Chassahowitzka Bay; Chiefland 
SW; Choctaw Beach; Chokoloskee; Clearwater; Clive Key; Cobb Rocks; 
Cockroach Bay; Crawfordville East; Crooked Island; Crooked Point; 
Cross City SW; Crystal River; Destin; Dog Island; Dunedin; East 
Pass; Egmont Key; El Jobean; Elfers; Englewood; Englewood NW; 
Estero; Everglades City; Fivay Junction; Flamingo; Fort Barrancas; 
Fort Myers Beach; Fort Myers SW; Fort Walton Beach; Freeport; Gandy 
Bridge; Garcon Point; Gator Hook Swamp; Gibsonton; Goose Island; 
Grayton Beach; Green Point; Gulf Breeze; Harney River; Harold SE; 
Holley; Holt SW; Homosassa; Horseshoe Beach; Indian Pass; Jackson 
River; Jena; Keaton Beach; Laguna Beach; Lake Ingraham East; Lake 
Ingraham West; Lake Wimico; Laurel; Lebanon Station; Lighthouse 
Point; Lillian; Long Point; Lostmans River Ranger Station; Manlin 
Hammock; Marco Island; Mary Esther; Matlacha; McIntyre; Milton 
South; Miramar Beach; Myakka River; Naples North; Naples South; 
Navarre; New Inlet; Niceville; Nutall Rise; Ochopee; Okefenokee 
Slough; Oldsmar; Orange Beach; Oriole Beach; Overstreet; Ozello; 
Pace; Palmetto; Panama City; Panama City Beach; Panther Key; Pass-A-
Grille Beach; Pavillion Key; Pensacola; Perdido Bay; Pickett Bay; 
Pine Island Center; Placida; Plover Key; Point Washington; Port Boca 
Grande; Port Richey; Port Richey NE; Port Saint Joe; Port Tampa; 
Punta Gorda; Punta Gorda SE; Punta Gorda SW; Red Head; Red Level; 
Rock Islands; Royal Palm Hammock; Safety Harbor; Saint Joseph Point; 
Saint Joseph Spit; Saint Marks; Saint Marks NE; Saint Petersburg; 
Saint Teresa Beach; Salem SW; Sandy Key; Sanibel; Sarasota; Seahorse 
Key; Seminole; Seminole Hills; Shark Point; Shark River Island; 
Shired Island; Snipe Island; Sopchoppy; South of Holley; Southport; 
Sprague Island; Spring Creek; Springfield; Steinhatchee; 
Steinhatchee SE; Steinhatchee SW; Sugar Hill; Sumner; Suwannee; 
Tampa; Tarpon Springs; Valparaiso; Venice; Vista; Waccassasa Bay; 
Ward Basin; Warrior Swamp; Weavers Station; Weeki Wachee Spring; 
West Bay; West Pass; West Pensacola; Whitewater Bay West; 
Withlacoochee Bay; Wulfert; Yankeetown.
    Louisiana (1:24,000 scale): Alligator Point; Barataria Pass; 
Bastian Bay; Bay Batiste; Bay Coquette; Bay Courant; Bay Dosgris; 
Bay Ronquille; Bay Tambour; Bayou Blanc; Bayou Lucien; Belle Isle; 
Belle Pass; Big Constance Lake; Black Bay North; Black Bay South; 
Breton Islands; Breton Islands SE; Buras; Burrwood Bayou East; 
Burwood Bayou West; Calumet Island; Cameron; Caminada Pass; Cat 
Island; Cat Island Pass; Central Isles Dernieres; Chandeleur Light; 
Chef Mentur; Cheniere Au Tigre; Cocodrie; Coquille Point; Cow 
Island; Creole; Cypremort Point; Deep Lake; Dixon Bay; Dog Lake; 
Door Point; East Bay Junop; Eastern Isles; Dernieres; Ellerslie; 
Empire; English Lookout; False Mouth Bayou; Fearman Lake; Floating 
Turf Bayou; Fourleague Bay; Franklin; Freemason Island; Garden 
Island Pass; Grand Bayou; Grand Bayou du Large; Grand Chenier; Grand 
Gosier Islands; Grand Isle; Hackberry Beach; Hammock Lake; Happy 
Jack; Hebert Lake; Hell Hole Bayou; Hog Bayou; Holly Beach; 
Intercoastal City; Isle Au Pitre; Jacko Bay; Johnson Bayou; Kemper; 
Lake Athanasio; Lake Cuatro Caballo; Lake Eloi; Lake Eugene; Lake 
Felicity; Lake La Graisse; Lake Merchant; Lake Point; Lake Salve; 
Lake Tambour; Leeville; Lena Lagoon; Lost Lake; Main Pass; 
Malheureux Point; Marone Point; Martello Castle; Mink Bayou; 
Mitchell Key; Morgan City SW; Morgan Harbor; Mound Point; Mulberry 
Island East; Mulberry Island West; New Harbor Islands; North 
Islands; Oak Mound Bayou; Oyster Bayou; Pass A Loutre East; Pass A 
Loutre West; Pass du Bois; Pass Tante Phine; Pecan Island; Pelican 
Pass; Peveto Beach; Pilottown; Plumb Bayou; Point Au Fer; Point Au 
Fer NE; Point Chevreuil; Point Chicot; Port Arthur South; Port 
Sulphur; Pte. Aux Marchuttes; Proctor Point; Pumpkin Islands; 
Redfish Point; Rollover Lake; Sabine Pass; Saint Joe Pass; Smith 
Bayou; South of South Pass; South Pass; Stake Islands; Taylor Pass; 
Texas Point; Three Mile Bay; Tigre Lagoon; Timbalier Island; 
Triumph; Venice; Weeks; West of Johnson Bayou; Western Isles 
Dernieres; Wilkinson Bay; Yscloskey.
    Mississippi (1:24,000 scale): Bay Saint Louis; Biloxi; Cat 
Island; Chandeleur Light; Deer Island; Dog Keys Pass; English 
Lookout; Gautier North; Gautier South; Grand Bay SW; Gulfport North; 
Gulfport NW; Gulfport South; Horn Island East; Horn Island West; 
Isle Au Pitre; Kreole; Ocean Springs; Pascagoula North; Pascagoula 
South; Pass Christian; Petit Bois Island; Saint Joe Pass; Ship 
Island; Waveland.
    Texas (1:24,000 scale): Allyns Bright; Anahuac; Aransas Pass; 
Austwell; Bacliff; Bayside; Big Hill Bayou; Brown Cedar Cut; Caplen; 
Carancahua Pass; Cedar Lakes East; Cedar Lakes West; Cedar Lane NE; 
Christmas Point; Clam Lake; Corpus Christi; Cove; Crane Islands NW; 
Crane Islands SW; Decros Point; Dressing Point; Estes; Flake; 
Freeport; Frozen Point; Galveston; Green Island; Hawk Island; High 
Island; Hitchcock; Hoskins Mound; Jones Creek; Keller Bay; Kleberg 
Point; La Comal; La Leona; La Parra Ranch NE; Laguna Vista; Lake 
Austin; Lake Como; Lake Stephenson; Lamar; Long Island; Los Amigos; 
Windmill; Maria Estella Well; Matagorda; Matagorda SW; Mesquite Bay; 
Mission Bay; Morgans Point; Mosquito Point; Mouth of Rio Grande; Mud 
Lake; North of Port Isabel NW; North of Port Isabel SW; Oak Island; 
Olivia; Oso Creek NE; Oyster Creek; Palacios; Palacios NE; Palacios 
Point; Palacios SE; Panther Point; Panther Point NE; Pass Cavallo 
SW; Pita Island; Point Comfort; Point of Rocks; Port Aransas; Port 
Arthur South; Port Bolivar; Port Ingleside; Port Isabel; Port Isabel 
NW; Port Lavaca East; Port Mansfield; Port O'Connor; Portland; 
Potrero Cortado; Potrero Lopeno NW; Potrero Lopeno SE; Potrero 
Lopeno SW; Rockport; Sabine Pass; San Luis Pass; Sargent; Sea Isle; 
Seadrift; Seadrift NE; Smith Point; South Bird Island; South Bird 
Island NW; South Bird Island SE; South of Palacios Point; South of 
Potrero Lopeno NE; South of Potrero Lopeno NW; South of Potrero 
Lopeno SE; South of Star Lake; St. Charles Bay; St. Charles Bay SE; 
St. Charles Bay SW; Star Lake; Texas City; Texas Point; The Jetties; 
Three Islands; Tivoli SE; Turtle Bay; Umbrella Point; Virginia 
Point; West of Johnson Bayou; Whites Ranch; Yarborough Pass.

PART 556--LEASING OF SULPHUR OR OIL AND GAS IN THE OUTER 
CONTINENTAL SHELF

Subpart A--Outer Continental Shelf Oil, Gas, and Sulphur Management, 
General
Sec.
556.0 Authority for information collection.
556.1 Purpose.
556.2 Policy.
556.4 Authority.
556.5 Definitions.
556.7 Cross references.
556.8 Leasing maps and diagrams.
556.10 Information to States.
556.11 Helium.
556.12 Supplemental sales.
Subpart B--Oil and Gas Leasing Program
556.16 Receipt and consideration of nominations; public notice and 
participation.
556.17 Review by State and local governments and other persons.
556.19 Periodic consultation with interested parties.
556.20 Consideration of coastal zone management program.
Subpart C--Reports From Federal Agencies
556.22 General.
Subpart D--Call for Information and Nominations
556.23 Information on areas.
556.25 Areas near coastal States.
Subpart E--Area Identification and Tract Size
556.26 General.
556.28 Tract size.
Subpart F--Lease Sales
556.29 Proposed notice of sale.
556.31 State comments.
556.32 Notice of sale.
Subpart G--Issuance of Leases
556.35 Qualifications of lessees.
556.37 Lease term.
556.38 Joint bidding provisions.
556.40 Definitions.
556.41 Joint bidding requirements.
556.43 Chargeability for production.

[[Page 64683]]

556.44 Bids disqualified.
556.46 Submission of bids.
556.47 Award of leases.
556.49 Lease form.
556.50 Dating of leases.
Subpart H--Rentals and Royalties [Reserved]
Subpart I--Bonding
556.52 Bond requirements for an oil and gas or sulphur lease.
556.53 Additional bonds.
556.54 General requirements for bonds.
556.55 Lapse of bond.
556.56 Lease-specific abandonment accounts.
556.57 Using a third-party guarantee instead of a bond.
556.58 Termination of the period of liability and cancellation of a 
bond.
556.59 Forfeiture of bonds and/or other securities.
Subpart J--Assignments, Transfers, and Extensions
556.62 Assignment of lease or interest in lease.
556.63 Service fees.
556.64 How to file transfers.
556.65 Attorney General review.
556.67 Separate filings for assignments.
556.68 Effect of assignment of a particular tract.
556.70 Extension of lease by drilling or well reworking operations.
556.71 Directional drilling.
556.72 Compensatory payments as production.
Subpart K--Termination of Leases
556.76 Relinquishment of leases or parts of leases.
556.77 Cancellation of leases.
Subpart L--Section 6 Leases
556.79 Effect of regulations on lease.
556.80 Leases of other minerals.
Subpart M--Studies
556.82 Environmental studies.
Subpart N--Bonus or Royalty Credits for Exchange of Certain Leases 
Offshore Florida
556.90 Which leases may I exchange for a bonus or royalty credit?
556.91 How much bonus or royalty credit will BOEM grant in exchange 
for a lease?
556.92 What must I do to obtain a bonus or royalty credit?
556.93 How is the bonus or royalty credit allocated among multiple 
lease owners?
556.94 How may I use the bonus or royalty credit?
556.95 How do I transfer a bonus or royalty credit to another 
person?

Appendix to Part 556--Oil and Gas Cash Bonus Bid

    Authority: 31 U.S.C. 9701, 42 U.S.C. 6213, 43 U.S.C. 1334, Pub. 
L. 109-432.

Subpart A--Outer Continental Shelf Oil, Gas, and Sulphur 
Management, General

Sec.  556.0  Authority for information collection.

    (a) The Office of Management and Budget (OMB) has approved the 
information collection requirements in this part under 44 U.S.C. 3501 
et seq. OMB assigned the control number 1010-0006. The title of this 
information collection is ``30 CFR part 556, Leasing of Sulphur or Oil 
and Gas in the Outer Continental Shelf.''
    (b) BOEM collects this information to determine if the applicant 
filing for a lease on the Outer Continental Shelf is qualified to hold 
such a lease. Response is required to obtain a benefit according to 43 
U.S.C. 1331 et seq. BOEM will protect proprietary information collected 
according to section 26 of the OCS Lands Act and 30 CFR 556.10.
    (c) An agency may not conduct or sponsor, and a person is not 
required to respond to a collection of information unless it displays a 
currently valid OMB control number.
    (d) Send comments regarding any aspect of the collection of 
information under this part, including suggestions for reducing the 
burden, to the Information Collection Clearance Officer, Bureau of 
Ocean Energy Management, 381 Elden Street, Herndon, VA 20170.

Sec.  556.1  Purpose.

    The purpose of the regulations in this part is to establish the 
procedures under which the Secretary of the Interior (Secretary) will 
exercise the authority to administer a leasing program for oil, gas and 
sulphur. The procedures under which the Secretary will exercise the 
authority to administer a program to grant rights-of-use and easements 
are addressed in other parts.

Sec.  556.2  Policy.

    The management of Outer Continental Shelf resources is to be 
conducted in accordance with the findings, purposes and policy 
directions provided by the Outer Continental Shelf Lands Act Amendments 
of 1978 (43 U.S.C. 1332, 1801, 1802), and other Executive, legislative, 
judicial and Departmental guidance. The Secretary of the Interior shall 
consider available environmental information in making decisions 
affecting Outer Continental Shelf resources.

Sec.  556.4  Authority.

    The Outer Continental Shelf Lands Act (OCSLA) (43 U.S.C. 1331 et 
seq.) authorizes the Secretary of the Interior to issue, on a 
competitive basis, leases for oil and gas, and sulphur, in submerged 
lands of the outer Continental Shelf (OCS). The Act authorizes the 
Secretary to grant rights-of-way, rights-of-use and easements through 
the submerged lands of the OCS. The Energy Policy and Conservation Act 
of 1975 (42 U.S.C. 6213), prohibits joint bidding by major oil and gas 
producers.

Sec.  556.5  Definitions.

    As used in this part, the term:
    (a) Act refers to the Outer Continental Shelf Lands Act of August 
7, 1953 (43 U.S.C. 1331 et seq.) as amended.
    (b) Director means the Director, Bureau of Ocean Energy Management.
    (c) OCS means the Outer Continental Shelf, as that term is defined 
in 43 U.S.C. 1331(a).
    (d) Secretary means the Secretary of the Interior or an official 
authorized to act on the Secretary's behalf.
    (e) BOEM means Bureau of Ocean Energy Management.
    (f) Coastal zone means the coastal waters (including the lands 
therein and thereunder) and the adjacent shorelands (including the 
waters therein and thereunder), strongly influenced by each other and 
in proximity to the shorelines of the several coastal States, and 
includes islands, transition and intertidal areas, salt marshes, 
wetlands, and beaches, which zone extends seaward to the outer limit of 
the United States territorial sea and extends inland from the shore 
lines to the extent necessary to control shorelands, the uses of which 
have a direct and significant impact on the coastal waters, and the 
inward boundaries of which may be identified by the several coastal 
States, pursuant to the authority of section 305(b)(1) of the Coastal 
Zone Management Act of 1972 (16 U.S.C. 1454(b)(1));
    (g) Affected State means, with respect to any program, plan, lease 
sale, or other activity, proposed, conducted, or approved pursuant to 
the provisions of the act, any State:
    (1) The laws of which are declared, pursuant to section 4(a)(2) of 
the Act, to be the law of the United States for the portion of the 
Outer Continental Shelf on which such activity is, or is proposed to be 
conducted;
    (2) Which is, or is proposed to be, directly connected by 
transportation facilities to any artificial island or structure 
referred to in section 4(a)(1) of the Act;
    (3) Which is receiving, or in accordance with the proposed activity 
will receive, oil for processing, refining, or transshipment which was 
extracted

[[Page 64684]]

from the Outer Continental Shelf 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 Outer Continental Shelf; 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 oilspill, blowout, or release of oil or 
gas from vessels, pipelines, or other transshipment facilities;
    (h) Marine environment means the physical, atmospheric, and 
biological components, conditions, and factors which interactively 
determine the productivity, state, conditions, and quality of the 
marine ecosystem, including the waters of the high seas, the contiguous 
zone, transitional and intertidal areas, salt marshes, and wetlands 
within the coastal zone and on the Outer Continental Shelf;
    (i) Coastal environment means the physical, atmospheric, and 
biological components, conditions, and factors which interactively 
determine the productivity, state, conditions, and quality of the 
terrestrial ecosystem from the shoreline inward to the boundaries of 
the coastal zone;
    (j) Human environment means the physical, social, and economic 
components, conditions, and factors which interactively determine the 
state, condition, and quality of living conditions, employment, and 
health of those affected, directly or indirectly, by activities 
occurring on the Outer Continental Shelf;
    (k) Mineral means oil, gas, and sulphur; it includes sand and 
gravel and salt used to facilitate the development and production of 
oil, gas, or sulphur.
    (l) Authorized officer means any person authorized by law or by 
delegation of authority to or within BOEM to perform the duties 
described in this part.
    (m) Bonus or royalty credit means a legal instrument or other 
written documentation, or an entry in an account managed by the 
Secretary that a bidder or lessee may use in lieu of any other monetary 
payment for--
    (1) A bonus due for a lease on the Outer Continental Shelf; or
    (2) A royalty due on oil or gas production from any lease located 
on the Outer Continental Shelf.
    (n) Central planning area means the Central Gulf of Mexico Planning 
Area of the Outer Continental Shelf, as designated in the document 
entitled ``Draft Proposed Program Outer Continental Shelf Oil and Gas 
Leasing Program 2007-2012,'' dated February 2006.
    (o) Coastline means the line of ordinary low water along that 
portion of the coast in direct contact with the open sea and the line 
marking the seaward limit of inland waters.
    (p) Desoto Canyon OPD means the official protraction diagram 
designated as Desoto Canyon which has a western edge located at the 
universal transverse mercator (UTM) X coordinate 1,346,400 in the North 
American Datum of 1927 (NAD 27).
    (q) Destin Dome OPD means the official protraction diagram 
designated as Destin Dome which has a western edge located at the 
universal transverse mercator (UTM) X coordinate 1,393,920 in the NAD 
27.
    (r) Eastern planning area means the Eastern Gulf of Mexico Planning 
Area of the Outer Continental Shelf, as designated in the document 
entitled ``Draft Proposed Program Outer Continental Shelf Oil and Gas 
Leasing Program 2007-2012,'' dated February 2006.
    (s) Pensacola OPD means the official protraction diagram designated 
as Pensacola which has a western edge located at the universal 
transverse mercator (UTM) X coordinate 1,393,920 in the NAD 27.

Sec.  556.7  Cross references.

    (a) For Bureau of Ocean Energy Management regulations governing 
exploration, development and production on leases, see 30 CFR parts 550 
and 570.
    (b) For BOEM regulations governing the appeal of an order or 
decision issued under the regulations in this part, see 30 CFR part 
590.
    (c) For multiple use conflicts, see the Environmental Protection 
Agency listing of ocean dumping sites--40 CFR part 228.
    (d) For related National Oceanic and Atmospheric Administration 
programs see:
    (1) Marine sanctuary regulations, 15 CFR part 922;
    (2) Fishermen's Contingency Fund, 50 CFR part 296;
    (3) Coastal Energy Impact Program, 15 CFR part 931;
    (e) For Coast Guard regulations on the oil spill liability of 
vessels and operators, see 33 CFR parts 132, 135, and 136.
    (f) For Coast Guard regulations on port access routes, see 33 CFR 
part 164.
    (g) For compliance with the National Environmental Policy Act, see 
40 CFR parts 1500 through 1508.
    (h) For Department of Transportation regulations on offshore 
pipeline facilities, see 49 CFR part 195.
    (i) For Department of Defense regulations on military activities on 
offshore areas, see 32 CFR part 252.

Sec.  556.8  Leasing maps and diagrams.

    (a) Any area of the OCS which has been appropriately platted as 
provided in paragraph (b) of this section, is subject to lease for any 
mineral not included in a subsisting lease issued under the act or 
meeting the requirements of subsection (a) of section 6 of the Act. 
Before any lease is offered or issued an area may be:
    (1) Withdrawn from disposition pursuant to section 12(a) of the 
Act; or
    (2) Designated as an area or part of an area restricted from 
operation under section 12(d) of the Act.
    (b) BOEM shall prepare leasing maps and official protraction 
diagrams of areas of the OCS. The areas included in each mineral lease 
shall be in accordance with the appropriate leasing map or official 
protraction diagram.

Sec.  556.10  Information to States.

    (a) The information covered in this section is prepared by or 
directly obtained by the Director. Such information is typically not 
considered to be proprietary or privileged, with the primary exception 
of specific indications of interest in an area by industry received in 
response to a Call for Information issued by the Secretary. This 
information and all other proprietary and privileged information 
obtained by or under the control of the Bureau of Ocean Energy 
Management may be released only in accordance with the regulations in 
30 CFR parts 550, 551, and 552.
    (b) The Director shall prepare an index to OCS information (see 30 
CFR 552.5). The index shall list all relevant actual or proposed 
programs, plans, reports, environmental impact statements, nominations 
information, environmental study reports, lease sale information and 
any similar type of relevant information including, modifications, 
comments and revisions, prepared by or directly obtained by the 
Director under the act. The index shall be sent on a regular basis to 
affected States and, upon request, it shall be sent to any affected 
local government. The

[[Page 64685]]

public shall be informed of the availability of the index.
    (c) Upon request, the Director shall transmit to affected States, 
local governments or the public, a copy of any information listed in 
the index which is subject to the control of the BOEM in accordance 
with the requirements and subject to the limitations of the Freedom of 
Information Act (5 U.S.C. 552) and regulations implementing said Act, 
and the regulations contained in 43 CFR part 2, except as provided in 
paragraph (d) of this section.
    (d) Upon request, the Director shall provide relative indications 
of interest in areas as well as any comments filed in response to a 
Call for Information for a proposed sale. However, no information 
transmitted shall identify any particular area with the name of any 
particular party so as not to compromise the competitive position of 
any participants in the process of indicating interest.

Sec.  556.11  Helium.

    (a) Each lease issued or continued under these regulations shall be 
subject to a reservation by the United States, under section 12(f) of 
the Act, of the ownership of and the right to extract helium from all 
gas produced from the leased area.
    (b) In case the United States elects to take the helium, the lessee 
shall deliver all gas containing helium, or the portion of gas desired, 
to the United States at any point on the leased area or at an onshore 
processing facility. Delivery shall be made in the manner required by 
the United States to such plants or reduction works as the United 
States may provide.
    (c) The extraction of helium shall not cause a reduction in the 
value of the lessee's gas or any other loss for which he is not 
reasonably compensated, except for the value of the helium extracted. 
The United States shall determine the amount of reasonable 
compensation. The United States shall have the right to erect, maintain 
and operate on the leased area any and all reduction works and other 
equipment necessary for the extraction of helium. The extraction of 
helium shall not cause substantial delays in the delivery of natural 
gas produced to the purchaser of that gas.

Sec.  556.12  Supplemental sales.

    (a) The Secretary may conduct a supplemental sale in accordance 
with the provisions of this section.
    (b) Supplemental sales shall be governed by the regulations in this 
part, except Sec.  556.22.
    (c) Supplemental sales shall be limited to blocks falling into one 
or more of the following categories:
    (1) Blocks for which bids were rejected during the calendar year 
preceding the year of the supplemental sale in which they are reoffered 
or blocks for which bids were rejected in the same calendar year as the 
supplemental sale in which they are reoffered, except that for the 
initial supplemental sale only blocks for which bids were rejected 
after October 1, 1987, may be reoffered. If, after the initial 
supplemental sale, a supplemental sale is not held annually for any 
reason, the relevant period for determining blocks eligible for a 
subsequent supplemental sale may be extended to include rejected bid 
blocks which were eligible for the supplemental sale not held.
    (2) Blocks for which the high bid was forfeited during the calendar 
year preceding the year of the supplemental sale in which they are 
reoffered or blocks for which high bids were forfeited in the same 
calendar year as the supplemental sale in which they are reoffered, 
except that for the initial supplemental sale only blocks for which 
high bids were forfeited after October 1, 1987, may be reoffered. If, 
after the initial supplemental sale, a supplemental sale is not held 
annually for any reason, the relevant period for determining blocks 
eligible for a subsequent sale may be extended to include forfeited bid 
blocks which were eligible for the supplemental sale not held.
    (3) Development blocks. Development blocks (including blocks 
susceptible to drainage) are blocks which are located on the same 
general geologic structure as an existing lease having a well with 
indicated hydrocarbons; the reservoir may or may not be interpreted to 
extend on to the block.
    (d) Supplemental sales shall not include blocks in the Central or 
Western Gulf of Mexico Planning Areas.
    (e) The Director may disclose the classification of blocks in 
supplemental sales as development blocks.

Subpart B--Oil and Gas Leasing Program

Sec.  556.16  Receipt and consideration of nominations; public notice 
and participation.

    (a) During preparation of a proposed 5-year leasing program, the 
Secretary shall invite and consider suggestions and relevant 
information for such program from Governors of affected States, local 
government, industry, other Federal agencies, including the Attorney 
General in consultation with the Federal Trade Commission, and all 
interested parties, including the general public. This request for 
information shall be issued as a notice in the Federal Register. Local 
governments wishing to respond to such request shall first submit their 
responses to the Governor of the State in which the local government is 
located.
    (b) The Secretary shall send letters to the Governors of the 
affected States requesting them to identify specific laws, goals, and 
policies which they believe should be considered by the Secretary in 
connection with the leasing program. The Secretary shall also request 
from the Secretary of Energy information on regional and national 
energy markets, on OCS production goals and on transportation networks.

Sec.  556.17  Review by State and local governments and other persons.

    (a)(1) The Secretary shall prepare a proposed leasing program. At 
least 60 days prior to publication of the proposed program in the 
Federal Register, a copy of the draft of the proposed program shall be 
forwarded to the Governor of each affected State for comment. The 
Governor may solicit comments from local governments in his or her 
State which the Governor determines will be affected by the proposed 
program.
    (2) The Secretary shall reply in writing to any comment on the 
draft of the proposed program from the Governor of an affected State 
which is received at least 15 days prior to the submission of the 
proposed program to the Congress and publication in the Federal 
Register. All such correspondence between the Secretary and Governor of 
such State shall accompany the proposed program when it is submitted to 
the Congress.
    (b) The proposed leasing program shall be submitted to the 
Governors of the affected States for review and comment at the time it 
is submitted to the Congress and the Attorney General and published in 
the Federal Register. The Governor of an affected State shall, upon 
request from any local government affected by the program, submit a 
copy of the proposed program to such local government. Comments and 
recommendations on any aspect of the proposed program may be submitted 
by a State or local government or other persons to the Secretary within 
90 days after the date of its publication in the Federal Register. 
Comments and recommendations from local governments shall be submitted 
first to the Governor of the State in which the local government is 
located.

[[Page 64686]]

    (c) At least 60 days prior to approving the final leasing program 
and any later significant revision, the Secretary shall submit it to 
the President and the Congress, together with any comments. The 
Secretary shall indicate in such submission why any specific 
recommendation of the Attorney General or of a State or local 
government was not accepted.

Sec.  556.19  Periodic consultation with interested parties.

    The Secretary shall provide for periodic consultation with State 
and local governments, existing and potential oil and gas lessees and 
permittees, and representatives of other individuals or organizations 
engaged in any activity in or on the OCS, including those involved in 
fish and shellfish recovery, and recreational activities. This 
consultation shall take place primarily through appropriate public 
notice as described in Sec. Sec.  556.16 and 556.17 and through the OCS 
Advisory Board and its committees, on a regional and National basis. 
Meetings of the OCS Advisory Board shall be held on specific issues as 
required by the Board's charter.

Sec.  556.20  Consideration of coastal zone management program.

    In the development of the leasing program, consideration shall be 
given to the coastal zone management program being developed or 
administered by an affected coastal State under section 305 or 306 of 
the Coastal Zone Management Act of 1972 as amended, (16 U.S.C. 1454, 
1455). Information concerning the relationship between a State's 
coastal zone management program and OCS oil and gas activity shall be 
requested from the Governors of the affected coastal States and from 
the Secretary of Commerce prior to the development of the proposed 
leasing program at the time information is requested under Sec.  556.16 
of this part.

Subpart C--Reports From Federal Agencies

Sec.  556.22  General.

    For oil and gas lease sales shown in an approved leasing schedule 
and as the need arises for other mineral leasing, the Director shall 
prepare a report describing the general geology and potential mineral 
resources of the area under consideration. The Director may request 
other interested Federal Agencies to prepare reports describing, to the 
extent known, any other valuable resources contained within the general 
area and the potential effect of mineral operations upon the resources 
or upon the total environment or other uses of the area.

Subpart D--Call for Information and Nominations

Sec.  556.23  Information on areas.

    (a) The Director may receive and consider indications of interest 
in areas for mineral leasing.
    (b) In accordance with an approved program and schedule for the 
leasing of OCS lands which may contain oil and gas, the Director shall 
issue Calls for Information and Nominations on areas for leasing of 
such minerals in specified areas. The Call for Information and 
Nominations shall be published in the Federal Register and may be 
published in other publications as desirable. Information on areas 
shall be addressed to the appropriate BOEM regional supervisor with a 
copy to any other office which may be specified in the Call. The 
Director shall also request comments on areas which should receive 
special concern and analysis. For an oil and gas lease sale Call Area, 
the Director may request comments concerning geological conditions, 
including bottom hazards; archaeological sites on the seabed or near 
shore; multiple uses of the proposed leasing area, including 
navigation, recreation, and fisheries; and other socioeconomic, 
biological, and environmental information.

Sec.  556.25  Areas near coastal States.

    (a) At the time information is solicited for leasing of areas 
within 3 geographical miles seaward of the seaward boundary of any 
coastal State, the Secretary shall provide the Governor of that State 
information required under section 8(g)(1) of the Act. The Director 
shall furnish information identifying the areas for leasing as well as 
all relevant available environmental data for such areas (See 30 CFR 
551.14).
    (b) After receipt of information on areas within the area described 
in paragraph (a) of this section, the Secretary shall inform the 
Governor of those areas that are to be given further consideration for 
leasing. The Secretary shall enter into consultation with the Governor 
to determine whether the area may contain oil or gas pools or fields 
underlying both the OCS and lands subject to the jurisdiction of the 
State.
    (c) After selection for leasing of those tracts which may have oil 
or gas pools or fields underlying both the OCS and lands under State 
jurisdiction, the Secretary shall offer the Governor an opportunity to 
enter into an agreement for the equitable disposition of revenues from 
such tracts under section 8(g)(2) of the Act.
    (d) If no agreement can be reached within 90 days of the 
Secretary's offer, the tracts may be leased and all revenues deposited 
in a separate Treasury account pending equitable disposition of the 
revenues under sections 8(g)(3) and (4) of the Act.

Subpart E--Area Identification and Tract Size

Sec.  556.26  General.

    (a) The Director, in consultation with appropriate Federal 
Agencies, shall recommend to the Secretary areas identified for 
environmental analysis and consideration for leasing. The Director, on 
his/her own motion, may include in the recommendation areas in which 
interest has not been indicated in response to a call. In making a 
recommendation, the Director shall consider all available environmental 
information, multiple-use conflicts, resource potential, industry 
interest and other relevant information. Comments received from States 
and local governments and interested parties in response to calls for 
information and nominations shall be considered in making 
recommendations. For supplemental sales provided for by Sec.  556.12 of 
this part, the Director's recommendation shall be replaced by a 
statement describing the results of the Director's consideration of the 
factors specified above in this section.
    (b) The Director shall evaluate fully the potential effect of 
leasing on the human, marine and coastal environments, and develop 
measures to mitigate adverse impacts, including lease stipulations. The 
views and recommendations of Federal agencies, State agencies, local 
governments, organizations, industries and the general public shall be 
used as appropriate. The Director may hold public hearings on the 
environmental analysis after appropriate notice.
    (c) In general, the Director shall seek to inform the public as 
soon as possible of additions or deletions that occur after the 
identification of areas.

Sec.  556.28  Tract size.

    (a) A tract selected for oil and gas leasing shall consist of a 
compact area not exceeding 5,760 acres, unless the authorized officer 
finds that a larger area is necessary to comprise a reasonable economic 
production unit.
    (b) The tract size for the leasing of other minerals shall be 
specified in the notice of sale.

[[Page 64687]]

Subpart F--Lease Sales

Sec.  556.29  Proposed notice of sale.

    (a) The Director shall in consultation with appropriate Federal 
agencies develop measures, including lease stipulations and conditions, 
to mitigate adverse impacts on the environments. For oil and gas lease 
sales, appropriate proposed stipulations and conditions shall be 
contained or referenced in the proposed notice of lease sale.
    (b) A proposed notice of lease sale shall be submitted to the 
Secretary for approval. All comments and recommendations received and 
the Director's findings or actions thereon, shall also be forwarded to 
the Secretary.
    (c) Upon approval by the Secretary, the proposed Notice of Sale 
shall be sent to the Governor of any affected State and a notice of its 
availability shall be published in the Federal Register.

Sec.  556.31  State comments.

    (a) Within 60 days after notice of a proposed lease sale, a 
Governor of any affected State or any affected local government in such 
State may submit recommendations to the Secretary regarding the size, 
timing or location of the proposed lease sale. Prior to submitting 
recommendations to the Secretary, any affected local government shall 
forward such recommendation to the Governor.
    (b) The Secretary shall accept such recommendations of the Governor 
and may accept recommendations of any affected local government if he 
determines, after having provided the opportunity for consultation, 
that they provide for a reasonable balance between the National 
interest and the well-being of the citizens of the affected State. A 
determination of the National interest shall be based on the findings, 
purposes and policies of the Act.
    (c) The Secretary shall communicate to the Governor, in writing, 
the reasons for his determination to accept or reject such Governor's 
recommendations, or to implement any alternative means identified in 
consultation with the Governor to provide for a reasonable balance 
between the National interest and the well-being of the citizens of the 
affected State.

Sec.  556.32  Notice of sale.

    (a) Upon approval of the Secretary, the Director shall publish the 
notice of lease sale in the Federal Register as the official 
publication, and may publish the notice in other publications. The 
publication in the Federal Register shall be at least 30 days prior to 
the date of the sale. The notice shall state the place and time at 
which bids shall be filed, and the place, date and hour at which bids 
shall be opened. The notice shall contain or reference a description of 
the areas to be offered for lease and any stipulations, terms and 
conditions of the sale.
    (b) Tracts shall be offered for lease by competitive sealed bidding 
under conditions specified in the notice of lease sale and in 
accordance with all applicable laws and regulations. A suggested format 
for bidder submissions appears in the appendix to this part.
    (c) The notice of lease sale shall contain a reference to the OCS 
lease form which shall be issued to successful bidders.
    (d) With the approval of the Secretary, the Director may defer any 
part of the payment of the cash bonus according to a schedule announced 
at the time of the notice of lease sale. Payment shall be made no later 
than 5 years after the date of the lease sale. The schedule shall 
contain provisions for guaranteed payment of a deferred bonus.
    (e) In order to obtain statistical information to determine which 
bidding alternatives best accomplish the purposes and policies of the 
Act, the Director may, until September 18, 1983, require each bidder to 
submit bids for any OCS area in accordance with more than one of the 
bidding systems described in section 8(a)(1) of the Act. No more than 
10 percent of the tracts offered each year shall contain such a 
requirement. Leases may be awarded using a bidding alternative selected 
at random for statistical purposes, if it is otherwise consistent with 
the purposes and policies of the Act.

Subpart G--Issuance of Leases

Sec.  556.35  Qualifications of lessees.

    (a) In accordance with section 8 of the Act, leases shall be 
awarded only to the highest responsible qualified bidder.
    (b) Mineral leases issued pursuant to section 8 of the Act may be 
held only by:
    (1) Citizens and nationals of the United States;
    (2) Aliens lawfully admitted for permanent residence in the United 
States as defined in 8 U.S.C. 1101(a)(20);
    (3) Private, public or municipal corporations organized under the 
laws of the United States or of any State or of the District of 
Columbia or territory thereof; or
    (4) Associations of such citizens, nationals, resident aliens, or 
private, public, or municipal corporations, States, or political 
subdivisions of States.
    (c) BOEM may disqualify you from acquiring any new lease holdings 
or lease assignments if your operating performance is unacceptable 
according to 30 CFR 550.135.

Sec.  556.37  Lease term.

    (a)(1) All oil and gas leases shall be issued for an initial period 
of 5 years, or not to exceed 10 years where the authorized officer 
finds that such longer period is necessary to encourage exploration and 
development in areas because of unusually deep water or other unusually 
adverse conditions.
    (2) If your oil and gas lease is in water depths between 400 and 
800 meters, it will have an initial lease term of 8 years unless BOEM 
establishes a different lease term under paragraph (a)(1) of this 
section.
    (3) For leases issued with an initial term of 8 years, you must 
begin an exploratory well within the first 5 years of the term to avoid 
lease cancellation.
    (b) An oil and gas lease shall continue after such initial period 
for as long as oil or gas is produced from the lease in paying 
quantities, or drilling or well reworking operations as approved by the 
Secretary are conducted. The term of an oil and gas lease is subject to 
further extension as provided in 30 CFR 556.73.
    (c) Sulphur leases shall be issued for a term not to exceed 10 
years and so long thereafter as sulphur is produced from the leasehold 
in paying quantities, or drilling, well reworking, plant construction, 
or other operations for the production of sulphur, as approved by the 
Secretary, are conducted thereon.

Sec.  556.38  Joint bidding provisions.

Sec.  556.40  Definitions.

    The following definitions apply to Sec. Sec.  556.38 through 556.44 
of this part.
    (a) Single bid means a bid submitted by one person for an oil and 
gas lease under section 8(a) of the Act.
    (b) Joint bid means a bid submitted by two or more persons for an 
oil and gas lease under section 8(a) of the Act.
    (c) Average daily production is the total of all production in an 
applicable production period which is chargeable under Sec.  556.43 of 
this title divided by the exact number of calendar days in the 
applicable production period.
    (d) Barrel means 42 U.S. gallons.
    (e) Crude oil means a mixture of liquid hydrocarbons including 
condensate that exists in natural underground reservoirs and remains 
liquid at atmospheric pressure after passing through surface separating 
facilities, but does not include liquid hydrocarbons produced from tar 
sand, gilsonite, oil shale, or coal.
    (f) An economic interest means any right to, or any right dependent 
upon,

[[Page 64688]]

production of crude oil, natural gas, or liquefied petroleum products 
and shall include, but not be limited to, a royalty interest, or 
overriding royalty interest, whether payable in cash or in kind, a 
working interest, a net profits interest, a production payment, or a 
carried interest.
    (g) Liquefied petroleum products means natural gas liquid products 
including the following: ethane, propane, butane, pentane, natural 
gasoline, and other natural gas products recovered by a process of 
absorption, adsorption, compression, or refrigeration cycling, or a 
combination of such processes.
    (h) Natural gas means a mixture of hydrocarbons and varying 
quantities of nonhydrocarbons that exist in the gaseous phase.
    (i) Oil and gas lease means an oil and gas lease either offered or 
issued pursuant to the provisions of the Act.
    (j) Owned means:
    (1) With respect to crude oil --having either an economic interest 
in or a power of disposition over the production of crude oil;
    (2) With respect to natural gas--having either an economic interest 
in or a power of disposition over the production of natural gas; and
    (3) With respect to liquefied petroleum products--having either an 
economic interest in or a power of disposition over any liquefied 
petroleum product at the time of completion of the liquefaction 
process.
    (k) Prior production period means the continuous 6-month period of 
January 1 through June 30 preceding November 1 through April 30 for 
joint bids submitted during the 6-month bidding period from November 1 
through April 30, and means the continuous 6-month period of July 1 
through December 31 preceding May 1 through October 31 for joint bids 
submitted during the 6-month bidding period from May 1 through October 
31.
    (l) Production: (1) Of crude oil means the volume of crude oil 
produced worldwide from reservoirs during the prior production period. 
The amount of such crude oil production shall be established by 
measurement of volumes delivered at the point of custody transfer 
(e.g., from storage tanks to pipelines, trucks, tankers, or other media 
for transport to refineries or terminals) with adjustments for:
    (i) Net differences between opening and closing inventories, and
    (ii) Basic sediment and water;
    (2) Of natural gas means the volume of natural gas produced 
worldwide from natural oil and gas reservoirs during the prior 
production period, with adjustments, where applicable, to reflect
    (i) The volume of gas returned to natural reservoirs; and
    (ii) The reduction of volume resulting from the removal of natural 
gas liquids and nonhydrocarbon gases.
    (3) Of liquefied petroleum products mean the volume of natural gas 
liquids produced from reservoir gas and liquefied at surface 
separators, field facilities, or gas processing plants worldwide during 
the prior production period; these liquefied petroleum products include 
the following:
    (i) Condensate--natural gas liquids recovered from gas well gas 
(associated and non-associated) in separators or field facilities;
    (ii) Gas plant products--natural gas liquids recovered from natural 
gas in gas processing plants and from field facilities. Gas plant 
products shall include the following as classified according to the 
standards of the Natural Gas Processors Association (NGPA) or the 
American Society for Testing and Materials (ASTM):
    (A) Ethane--C2H6
    (B) Propane--C3H8
    (C) Butane--C4H10 including all products 
covered by NGPA specifications for commercial butane.
    (1) Isobutane,
    (2) Normal butane,
    (3) Other butanes--all butanes not included as isobutane or normal 
butane;
    (D) Butane-Propane Mixtures--All products covered by NGPA 
specifications for butane-propane mixtures;
    (E) Natural Gasoline--A mixture of hydrocarbons extracted from 
natural gas, which meet vapor pressure, end point, and other 
specifications for natural gasoline set by NGPA;
    (F) Plant Condensate--A natural gas plant product recovered and 
separated as a liquid at gas inlet separators or scrubbers in 
processing plants or field facilities; and
    (G) Other Natural Gas Plant Products meeting refined product 
standards (i.e., gasoline, kerosene, distillate, etc.).
    (m) 6-month bidding period means the 6-month period of time:
    (1) From May 1 through October 31; or
    (2) From November 1 through April 30, respectively.

Sec.  556.41  Joint bidding requirements.

    (a) Any person who submits a joint bid for any oil and gas lease 
during a 6-month bidding period, and who was chargeable for the prior 
production period with an average daily production in excess of 1.6 
million barrels of crude oil, natural gas and liquefied petroleum 
products, shall have filed under oath with the Director, a Statement of 
Production of crude oil, natural gas and liquefied petroleum products, 
hereinafter referred to as a Statement of Production, no later than 45 
days prior to the commencement of the applicable 6-month bidding period 
of May 1 through October 31, and November 1 through April 30. 
Statements of Production shall be submitted to the Director, BOEM 
(Attention: Offshore Leasing Management Division), Washington, DC 
20240. The Statement of Production shall indicate that the person was 
chargeable, in accordance with Sec.  556.43 of this part, with an 
average daily production in excess of 1.6 million barrels of crude oil, 
natural gas and liquefied petroleum products for the prior production 
period. The Director shall publish semi-annually in the Federal 
Register a ``List of Restricted Joint Bidders'' to be effective 
immediately upon publication and to continue in force and effect until 
a subsequent list is published. The ``List of Restricted Joint 
Bidders'' shall consist of those persons, who in the judgment of the 
Director, based on information available to him, including, but not 
limited to, sworn Statements of Production, are chargeable under Sec.  
556.43 of this part with an average daily production in excess of 1.6 
million barrels of crude oil, natural gas and liquefied petroleum 
products for the prior production period.
    (b) When a person is placed on the List of Restricted Joint Bidders 
the Director shall serve that person either personally or by certified 
mail, return receipt requested, with a copy of the Director's Order 
placing that person on the List of Restricted Joint Bidders. Any appeal 
from that Order or from an adverse effect of that Order shall be made 
in accordance with the provisions of 43 CFR part 4.
    (c) The submission of a Statement of Production or of a detailed 
Report of Production under Sec.  556.46(g) of this part which 
misrepresents the chargeable production of the reporting person shall 
constitute failure to comply with these regulations and any lease 
awarded in reliance on that Statement or Report of Production may be 
canceled, pursuant to section 8(o) of the Act and regulations issued 
there under as having been obtained by fraud or misrepresentation.
    (d) The Secretary may exempt a person from the provisions of 
Sec. Sec.  556.41(a), 556.44, 556.46(g) and 556.62(b) of this part if 
it is found, on the record, after an opportunity for an agency hearing, 
that lands being offered have extremely high cost exploration and 
development problems and that

[[Page 64689]]

exploration and development will not occur on such lands unless the 
exemption is granted.

Sec.  556.43  Chargeability for production.

    (a) As used in this section the following definitions shall 
control:
    (1) Person means a natural person or company.
    (2) Company means a corporation, a partnership, an association, a 
joint-stock company, a trust, a fund, or any group of persons whether 
incorporated or not; it also means any receiver, trustee in bankruptcy, 
or similar official acting for such a company.
    (3) Subsidiary means a company 50 percent or more of whose stock or 
other interest having power to vote for the election of directors, 
trustees, or other similar controlling body of the company is directly 
or indirectly owned, controlled, or held with the power to vote by 
another company; a subsidiary shall be deemed a subsidiary of the other 
company owning, controlling, or holding 50 percent or more of the stock 
or other voting interest.
    (4) Security or securities means any note, stock, treasury stock, 
bond, debenture, evidence of indebtedness, certificate of interest or 
participation in any profit-sharing agreement, collateral-trust 
certificate, pre-organization certificate or subscription, transferable 
share, investment contract, voting-trust certificate, certificate of 
deposit for a security, fractional undivided interest in oil, gas, or 
other mineral rights, or, in general, any interest or instrument 
commonly known as a ``security'' or any certificate of interest or 
participation in, temporary or interim certificate for, receipt for, 
guarantee of, or warrant or right to subscribe to or purchase any of 
the foregoing.
    (b) A person filing a Statement of Production under Sec.  556.41 of 
this part shall be charged with the following production during the 
applicable prior production period:
    (1) The average daily production in barrels of crude oil, natural 
gas, and liquefied petroleum products which it owned worldwide;
    (2) The average daily production in barrels of crude oil, natural 
gas, and liquefied petroleum products owned worldwide by every 
subsidiary of the reporting person;
    (3) The average daily production in barrels of crude oil, natural 
gas, and liquefied petroleum products owned worldwide by any person or 
persons of which the reporting person is a subsidiary; and
    (4) The average daily production in barrels of crude oil, natural 
gas, and liquefied petroleum products owned worldwide by any 
subsidiary, other than the reporting person, of any person or persons 
of which the reporting person is a subsidiary.
    (c) A person filing a Statement of Production shall be charged 
with, in addition to the production chargeable under paragraph (b) of 
this section, but not in duplication thereof, its proportionate share 
of the average daily production in barrels of crude oil, natural gas, 
and liquefied petroleum products owned worldwide by every person:
    (1) Which has an interest in the reporting person, and
    (2) In which the reporting person has an interest, whether the 
interest referred to in paragraphs (c)(1) and (2) of this section is by 
virtue of ownership of securities or other evidence of ownership, or by 
participation in any contract, agreement, or understanding respecting 
the control of any person or of any person's production of crude oil, 
natural gas, or liquefied petroleum products, equal to said interest. 
As used in paragraph (c) of this section ``interest'' means an interest 
of at least 5 percent of the ownership or control of a person.
    (d) All measurements of crude oil and liquefied petroleum products 
under this section shall be at 60 [deg]F.
    (e)(1) For purposes of computing production of natural gas under 
Sec.  556.41 of this part, chargeability under this section, and 
reporting under Sec.  556.46(g) of this part, 5,626 cubic feet of 
natural gas at 14.73 pounds per square inch (msl) shall equal one 
barrel.
    (2) For purposes of computing production of liquefied petroleum 
products under Sec.  556.41 of this part, chargeability under Sec.  
556.46(g) of this part, 1.454 barrels of natural gas liquids at 60 
[deg]F shall equal one barrel of crude oil.

Sec.  556.44  Bids disqualified.

    The following bids for any oil and gas lease shall be disqualified 
and rejected in their entirety:
    (a) A joint bid submitted by 2 or more persons who are on the 
effective List of Restricted Joint Bidders; or
    (b)(1) A joint bid submitted by two or more persons when 1 or more 
of those persons is chargeable for the prior production period with an 
average daily production in excess of 1.6 million barrels of crude oil, 
natural gas and liquefied petroleum products and has not filed a 
Statement of Production as required by Sec.  556.41 of this part for 
the applicable 6-month bidding period, or
    (2) Any of those persons have failed or refused to file a detailed 
report of production when required to do so under Sec.  556.46(g) of 
this part, or
    (c) A single or joint bid submitted pursuant to an agreement 
(whether written or oral, formal or informal, entered into or arranged 
prior to or simultaneously with the submission of such single or joint 
bid, or prior to or simultaneously with the award of the bid upon the 
tract) which provides:
    (1) For the assignment, transfer, sale, or other conveyance of less 
than a 100 percent interest in the entire tract on which the bid is 
submitted, by a person or persons on the List of Restricted Joint 
Bidders, effective on the date of submission of the bid, to another 
person or persons on the same List of Restricted Joint Bidders; or
    (2) For the assignment, sale, transfer or other conveyance of less 
than a 100 percent interest in any fractional interest in the entire 
tract (which fractional interest was originally acquired by the person 
making the assignment, sale, transfer or other conveyance, under the 
provisions of the act) by a person or persons on the List of Restricted 
Joint Bidders, effective on the date of submission of the bid, to 
another person or persons on the same List of Restricted Joint Bidders; 
or
    (3) For the assignment, sale, transfer, or other conveyance of any 
interest in a tract by a person or persons not on the List of 
Restricted Joint Bidders, effective on the date of submission of the 
bid, to 2 or more persons on the same List of Restricted Joint Bidders; 
or
    (4) For any of the types of conveyances described in paragraphs 
(c)(1), (2) or (3) of this section where any party to the conveyance is 
chargeable for the prior production period with an average daily 
production in excess of 1.6 million barrels of crude oil, natural gas 
and liquefied petroleum products and has not filed a Statement of 
Production pursuant to Sec.  556.41 of this part for the applicable 6-
month bidding period. Assignments expressly required by law, 
regulation, lease or stipulation to lease shall not disqualify an 
otherwise qualified bid; or
    (d) A bid submitted by or in conjunction with a person who has 
filed a false, fraudulent or otherwise intentionally false or 
misleading detailed Report of Production.

Sec.  556.46  Submission of bids.

    (a) A separate sealed bid shall be submitted for each tract unit 
bid upon as described in the notice of lease sale. A bid may not be 
submitted for less than an entire tract.
    (b) BOEM requires a deposit for each bid. The notice of sale will 
specify the

[[Page 64690]]

bid deposit amount and method of payment.
    (c) If the bidder is an individual a statement of citizenship shall 
accompany the bid.
    (d) If the bidder is an association (including a partnership), the 
bid shall be accompanied by a certified statement indicating the State 
in which it is registered and that it is authorized to hold mineral 
leases on the OCS, or appropriate reference to statements or records 
previously submitted to a BOEM OCS office (including material submitted 
in compliance with prior regulations).
    (e) If the bidder is a corporation, the following information shall 
be submitted with the bid:
    (1) A statement certified by the corporate Secretary or Assistant 
Secretary over the corporate seal showing the State in which it was 
incorporated and that it is authorized to hold mineral leases on the 
OCS, or appropriate reference to statements or records previously 
submitted to a BOEM OCS office (including material submitted in 
compliance with prior regulations).
    (2) Evidence of authority of persons signing to bind the 
corporation. Such evidence may be in the form of either a certified 
copy of the minutes of the board of directors or of the bylaws 
indicating that the person signing has authority to do so; or a 
certificate to that effect signed by the Secretary or Assistant 
Secretary of the corporation over the corporate seal, or appropriate 
reference to statements or records previously submitted to a BOEM OCS 
office (including material submitted in compliance with prior 
regulations). Bidders are advised to keep their filings current.
    (3) The bid shall be executed in conformance with corporate 
requirements.
    (f) Bidders should be aware of the provisions of 18 U.S.C. 1860, 
prohibiting unlawful combination or intimidation of bidders.
    (g) To verify the accuracy of any statement submitted pursuant to 
Sec.  556.41 of this part, the Director may require the person 
submitting such information to:
    (1) Submit no later than 30 days after receipt of the request by 
the Director, a detailed Report of Production which shall list, in 
barrels, the average daily production of crude oil, natural gas and 
liquefied petroleum products chargeable to the reporting person in 
accordance with Sec.  556.43 of this part for the prior production 
period, and
    (2) Permit the inspection and copying by an official of the 
Department of the Interior of such documents, records of production of 
crude oil, natural gas and liquefied petroleum products, analyses and 
other material as are necessary to demonstrate the accuracy of any 
statement or information contained in any Report of Production.
    (h) No bid for a lease may be submitted if the Secretary finds, 
after notice and hearing, that the bidder is not meeting due diligence 
requirements on other OCS leases.

Sec.  556.47  Award of leases.

    (a) Sealed bids received in response to the notice of lease sale 
shall be opened at the place, date and hour specified in the notice. 
The opening of bids is for the sole purpose of publicly announcing and 
recording the bids received and no bids shall be accepted or rejected 
at that time.
    (b) The United States reserves the right to reject any and all bids 
received for any tract, regardless of the amount offered.
    (c) In the event the highest bids are tie bids, the tie bidders 
(unless they would be disqualified under Sec.  556.35(b) of this part, 
or disqualified under Sec.  556.44 of this part if their bids had been 
joint bids) may file with the Director, within 15 days after 
notification, an agreement to accept the lease jointly; otherwise all 
bids shall be rejected.
    (d) Pursuant to section 8(c) of the Act, the Attorney General may 
review the results of the lease sale prior to the acceptance of bids 
and issuance of leases.
    (e)(1) The decision of the authorized officer on bids shall be the 
final action of the Department, subject only to reconsideration by the 
Secretary, pursuant to written request, of the rejection of the high 
bid. The delegation of review authority to the Office of Hearings and 
Appeals shall not be applicable to decisions on high bids for leases on 
the Outer Continental Shelf.
    (2) The authorized officer must accept or reject the bid within 90 
days. The authorized officer may extend the time period for acceptance 
or rejection of a bid for 15 working days or longer, if circumstances 
warrant. Any bid not accepted within the prescribed time period, 
including any extension thereof, is deemed rejected.
    (3) Any high bidder whose bid is rejected by the authorized officer 
may, within 15 days of such rejection, file with the Secretary, with a 
copy to the authorized officer, a written request for reconsideration 
accompanied by a statement of reasons. The Secretary shall respond in 
writing either affirming or reversing the decision of the authorized 
officer.
    (f) Written notice of the authorized officer's action shall be 
transmitted promptly to those bidders whose deposits have been held. If 
a bid is accepted, such notice shall transmit three copies of the lease 
to the successful bidder. As provided in 30 CFR 1218.155, the bidder 
shall, not later than the 11th business day after receipt of the lease, 
execute the lease, pay the first-year's rental, and unless deferred, 
pay the balance of the bonus bid. The bidder must also file a bond as 
required in Sec.  556.52 of this title. Deposits and any interest 
accrued shall be refunded on high bids subsequently rejected.
    (g) If the successful bidder fails to execute the lease within the 
prescribed time or otherwise comply with the applicable regulations the 
deposit shall be forfeited and disposed of as other receipts under the 
Act.
    (h) If, before the lease is executed on behalf of the United 
States, the land which would be subject to the lease is withdrawn or 
restricted from leasing, all deposits and any interest due shall be 
refunded.
    (i) If the awarded lease is executed by an agent acting on behalf 
of the bidder, the lease shall be accompanied by evidence that the 
bidder authorized the agent to execute the lease. When three copies of 
the lease are executed and returned to the authorized officer, the 
lease shall be executed on behalf of the United States, and one fully 
executed copy shall be transmitted to the successful bidder.
    (j) No lease or permit shall be issued for any area within 15 
statute miles of the boundaries of the Point Reyes Wilderness in 
California unless the State of California allows exploration, 
development or production activities in the adjacent navigable waters 
of the State under section 11(h) of the Act.

Sec.  556.49  Lease form.

    Oil and gas leases and leases for sulphur shall be issued on forms 
approved by the Director. Other mineral leases shall be issued on such 
forms as may be prescribed by the Secretary.

Sec.  556.50  Dating of leases.

    All leases issued under the regulations in this part shall be dated 
and become effective as of the first day of the month following the 
date leases are signed on behalf of the lessor. When prior written 
request is made, a lease may be dated and become effective as of the 
first day of the month within which it is so signed.

[[Page 64691]]

Subpart H--Rentals and Royalties [Reserved]

Subpart I--Bonding

Sec.  556.52  Bond requirements for an oil and gas or sulphur lease.

    This section establishes bond requirements for the lessee of an OCS 
oil and gas or sulphur lease.
    (a) Before BOEM will issue a new lease or approve the assignment of 
an existing lease to you as lessee, you or another record title owner 
for the lease must:
    (1) Maintain with the Regional Director a $50,000 lease bond that 
guarantees compliance with all the terms and conditions of the lease; 
or
    (2) Maintain a $300,000 areawide bond that guarantees compliance 
with all the terms and conditions of all your oil and gas and sulphur 
leases in the area where the lease is located; or
    (3) Maintain a lease or area wide bond in the amount required in 
Sec.  556.53(a) or (b) of this part.
    (b) For the purpose of this section, there are three areas. The 
area offshore the Atlantic Coast is included in the Gulf of Mexico. 
Areawide bonds issued in the Gulf of Mexico will cover oil and gas or 
sulphur operations offshore the Atlantic Coast. The three areas are:
    (1) The Gulf of Mexico and the area offshore the Atlantic Coast.
    (2) The area offshore the Pacific Coast States of California, 
Oregon, Washington, and Hawaii; and
    (3) The area offshore the Coast of Alaska.
    (c) The requirement to maintain a lease bond (or substitute 
security instruments) under paragraph (a)(1) of this section and Sec.  
556.53(a) and (b) is satisfied if your operator provides a lease bond 
in the required amount that guarantees compliance with all the terms 
and conditions of the lease. Your operator may use an areawide bond 
under this paragraph to satisfy your bond obligation.
    (d) If a surety makes payment to the United States under a bond or 
alternative form of security maintained under this section, the 
surety's remaining liability under the bond or alternative form of 
security is reduced by the amount of that payment. See paragraph (e) of 
this section for the requirement to replace the reduced bond coverage.
    (e) If the value of your surety bond or alternative security is 
reduced because of a default, or for any other reason, you must provide 
additional bond coverage sufficient to meet the security required under 
this subpart within 6 months, or such shorter period of time as the 
Regional Director may direct.
    (f) You may pledge U.S. Department of the Treasury (Treasury) 
securities instead of a bond. The Treasury securities you pledge must 
be negotiable for an amount of cash equal to the value of the bond they 
replace.
    (1) If you pledge Treasury securities under this paragraph (f), you 
must monitor their value. If their market value falls below the level 
of bond coverage required under this subpart, you must pledge 
additional Treasury securities to raise the value of the securities 
pledged to the required amount.
    (2) If you pledge Treasury securities, you must include authority 
for the Regional Director to sell them and use the proceeds when the 
Regional Director determines that you fail to satisfy any lease 
obligation.
    (g) You may pledge alternative types of security instruments 
instead of providing a bond if the Regional Director determines that 
the alternative security protects the interests of the United States to 
the same extent as the required bond.
    (1) If you pledge an alternative type of security under this 
paragraph, you must monitor the security's value. If its market value 
falls below the level of bond coverage required under this subpart, you 
must pledge additional securities to raise the value of the securities 
pledged to the required amount.
    (2) If you pledge an alternative type of security, you must include 
authority for the Regional Director to sell the security and use the 
proceeds when the Regional Director determines that you failed to 
satisfy any lease obligation.
    (h) If you fail to replace a deficient bond or to provide 
additional bond coverage upon demand, the Regional Director may:
    (1) Assess penalties under part 550, subpart N of this chapter;
    (2) Suspend production and other operations on your leases in 
accordance with 30 CFR 250.173; and
    (3) Initiate action to cancel your lease.

Sec.  556.53  Additional bonds.

    (a) This paragraph explains what bonds the lessee must provide 
before lease exploration activities commence.
    (1)(i) You must furnish the Regional Director a $200,000 bond that 
guarantees compliance with all the terms and conditions of the lease by 
the earliest of:
    (A) The date you submit a proposed Exploration Plan (EP) for 
approval;
    (B) The date you submit a request for approval of the assignment of 
a lease on which an EP has been approved; or
    (C) December 8, 1997, for any lease for which an EP has been 
approved.
    (ii) The Regional Director may authorize you to submit the $200,000 
lease exploration bond after you submit an EP but before he/she 
approves drilling activities under the EP.
    (iii) You may satisfy the bond requirement of this paragraph (a) by 
providing a new bond or by increasing the amount of your existing bond.
    (2) A $200,000 lease exploration bond pursuant to paragraph (a)(1) 
of this section need not be submitted and maintained if the lessee 
either:
    (i) Furnishes and maintains an areawide bond in the sum of $1 
million issued by a qualified surety and conditioned on compliance with 
all the terms and conditions of oil and gas and sulphur leases held by 
the lease on the OCS for the area in which the lessee is situated; or
    (ii) Furnishes and maintains a bond pursuant to paragraph (b)(2) of 
this section.
    (b) This paragraph explains what bonds you (the lessee) must 
provide before lease development and production activities commence.
    (1)(i) You must furnish the Regional Director a $500,000 bond that 
guarantees compliance with all the terms and conditions of the lease by 
the earliest of:
    (A) The date you submit a proposed Development and Production Plan 
(DPP) or Development Operations Coordination Document (DOCD) for 
approval;
    (B) The date you submit a request for approval of the assignment of 
a lease on which a DPP or DOCD has been approved; or
    (C) December 8, 1997, for any lease for which a DPP or DOCD has 
been approved.
    (ii) The Regional Director may authorize you to submit the $500,000 
lease development bond after you submit a DPP or DOCD, but before he/
she approves the installation of a platform or the commencement of 
drilling activities under the DPP or DOCD.
    (iii) You may satisfy the bond requirement of this paragraph by 
providing a new bond or by increasing the amount of your existing bond.
    (2) The lessee need not submit and maintain a $500,000 lease 
development bond pursuant to paragraph (b)(1) of this section if the 
lessee furnishes and maintains an areawide bond in the sum of $3 
million issued by a qualified surety and conditioned on compliance with 
all the terms and conditions of oil and gas and sulphur leases held by 
the

[[Page 64692]]

lessee on the OCS for the area in which the lease is situated.
    (c) When a lessee can demonstrate to the satisfaction of the 
authorized officer that wells and platforms can be abandoned and 
removed and the drilling and platform sites cleared of obstructions for 
less than the amount of lease bond coverage required under paragraph 
(b)(1) of this section, the authorized officer may accept a lease 
surety bond in an amount less than the prescribed amount but not less 
than the amount of the cost for well abandonment, platform removal, and 
site clearance.
    (d) The Regional Director may determine that additional security 
(i.e., security above the amounts prescribed in Sec. Sec.  556.52(a) 
and 556.53(a) and (b) of this part) is necessary to ensure compliance 
with the obligations under your lease and the regulations in this 
chapter.
    (1) The Regional Director's determination will be based on his/her 
evaluation of your ability to carry out present and future financial 
obligations demonstrated by:
    (i) Financial capacity substantially in excess of existing and 
anticipated lease and other obligations, as evidenced by audited 
financial statements (including auditor's certificate, balance sheet, 
and profit and loss sheet);
    (ii) Projected financial strength significantly in excess of 
existing and future lease obligations based on the estimated value of 
your existing OCS lease production and proven reserves of future 
production;
    (iii) Business stability based on 5 years of continuous operation 
and production of oil and gas or sulphur in the OCS or in the onshore 
oil and gas industry;
    (iv) Reliability in meeting obligations based on:
    (A) Credit rating(s); or
    (B) Trade references, including names and addresses of other 
lessees, drilling contractors, and suppliers with whom you have dealt; 
and
    (v) Record of compliance with laws, regulations, and lease terms.
    (2) You may satisfy the Regional Director's demand for additional 
security by increasing the amount of your existing bond or by providing 
a supplemental bond or bonds.
    (e) The Regional Director will determine the amount of supplemental 
bond required to guarantee compliance. The Regional Director will 
consider potential underpayment of royalty and cumulative obligations 
to abandon wells, remove platforms and facilities, and clear the 
seafloor of obstructions in the Regional Director's case-specific 
analysis.
    (f) If your cumulative potential obligations and liabilities either 
increase or decrease, the Regional Director may adjust the amount of 
supplemental bond required.
    (1) If the Regional Director proposes an adjustment, the Regional 
Director will:
    (i) Notify you and the surety of any proposed adjustment to the 
amount of bond required; and
    (ii) Give you an opportunity to submit written or oral comment on 
the adjustment.
    (2) If you request a reduction of the amount of supplemental bond 
required, you must submit evidence to the Regional Director 
demonstrating that the projected amount of royalties due the Government 
and the estimated costs of lease abandonment and cleanup are less than 
the required bond amount. If the Regional Director finds that the 
evidence you submit is convincing, he/she may reduce the amount of 
supplemental bond required.

Sec.  556.54  General requirements for bonds.

    (a) Any bond or other security that you, as lessee or operator, 
provide under this part must:
    (1) Be payable upon demand to the Regional Director;
    (2) Guarantee compliance with all of your obligations under the 
lease and regulations in this chapter; and
    (3) Guarantee compliance with the obligations of all lessees, 
operating rights owners and operators on the lease.
    (b) All bonds and pledges you furnish under this part must be on a 
form or in a form approved by the Associate Director for BOEM. Surety 
bonds must be issued by a surety that the Treasury certifies as an 
acceptable surety on Federal bonds and that is listed in the current 
Treasury Circular No. 570. You may obtain a copy of the current 
Treasury Circular No. 570 from the Surety Bond Branch, Financial 
Management Service, Department of the Treasury, East-West Highway, 
Hyattsville, MD 20782.
    (c) You and a qualified surety must execute your bond. When either 
party is a corporation, an authorized official for the party must sign 
the bond and attest to it by an imprint of the corporate seal.
    (d) Bonds must be noncancellable, except as provided in Sec.  
556.58 of this part. Bonds must continue in full force and effect even 
though an event occurs that could diminish, terminate, or cancel a 
surety obligation under State surety law.
    (e) Lease bonds must be:
    (1) A surety bond;
    (2) Treasury securities as provided in Sec.  556.52(f);
    (3) Another form of security approved by the Regional Director; or
    (4) A combination of these security methods.
    (f) You may submit a bond to the Regional Director executed on a 
form approved under paragraph (b) of this section that you have 
reproduced or generated by use of a computer. If you do this, and if 
the document omits terms or conditions contained on the form approved 
by the Associate Director for BOEM the bond you submit will be deemed 
to contain the omitted terms and conditions.

Sec.  556.55  Lapse of bond.

    (a) If your surety becomes bankrupt, insolvent, or has its charter 
or license suspended or revoked, any bond coverage from that surety 
terminates immediately. In that event, you must promptly provide a new 
bond in the amount required under Sec. Sec.  556.52 and 556.53 of this 
part to the Regional Director and advise the Regional Director of the 
lapse in your previous bond.
    (b) You must notify the Regional Director of any action filed 
alleging that you, your surety, or guarantor are insolvent or bankrupt. 
You must notify the Regional Director within 72 hours of learning of 
such an action. All bonds must require the surety to provide this 
information to you and directly to BOEM.

Sec.  556.56  Lease-specific abandonment accounts.

    (a) The Regional Director may authorize you to establish a lease-
specific abandonment account in a federally insured institution in lieu 
of the bond required under Sec.  556.53(d). The account must provide 
that, except as provided in paragraph (a)(3) of this section, funds may 
not be withdrawn without the written approval of the Regional Director.
    (1) Funds in a lease-specific abandonment account must be payable 
upon demand to BOEM and pledged to meet the lessee's obligations under 
30 CFR 250.1703.
    (2) You must fully fund the lease-specific abandonment account to 
cover all the costs of lease abandonment and site clearance as 
estimated by BOEM within the timeframe the Regional Director 
prescribes.
    (3) You must provide binding instructions under which the 
institution managing the account is to purchase Treasury securities 
pledged to BOEM under paragraph (d) of this section.

[[Page 64693]]

    (b) Any interest paid on funds in a lease-specific abandonment 
account will be treated as other funds in the account unless the 
Regional Director authorizes in writing the payment of interest to the 
party who deposits the funds.
    (c) The Regional Director may allow you to pledge Treasury 
securities that are made payable upon demand to the Regional Director 
to satisfy your obligation to make payments into a lease-specific 
abandonment account.
    (d) Before the amount of funds in a lease-specific abandonment 
account equals the maximum insurable amount as determined by the 
Federal Deposit Insurance Corporation or the Federal Savings and Loan 
Insurance Corporation, the institution managing the account must use 
the funds in the account to purchase Treasury securities pledged to 
BOEM under paragraph (c) of this section. The institution managing the 
lease specific-abandonment account will join with the Regional Director 
to establish a Federal Reserve Circular 154 account to hold these 
Treasury securities, unless the Regional Director authorizes the 
managing institution to retain the pledged Treasury securities in a 
separate trust account. You may obtain a copy of the current Treasury 
Circular No. 154 from the Surety Bond Branch, Financial Management 
Service, Department of the Treasury, East-West Highway, Hyattsville, MD 
20782.
    (e) The Regional Director may require you to create an overriding 
royalty or production payment obligation for the benefit of a lease-
specific account pledged for the abandonment and clearance of a lease. 
The required obligation may be associated with oil and gas or sulphur 
production from a lease other than the lease bonded through the lease-
specific abandonment account.

Sec.  556.57  Using a third-party guarantee instead of a bond.

    (a) When the Regional Director may accept a third-party guarantee. 
The Regional Director may accept a third-party guarantee instead of an 
additional bond under Sec.  556.53(d) if:
    (1) The guarantee meets the criteria in paragraph (c) of this 
section;
    (2) The guarantee includes the terms specified in paragraph (d) of 
this section;
    (3) The guarantor's total outstanding and proposed guarantees do 
not exceed 25 percent of its unencumbered net worth in the United 
States; and
    (4) The guarantor submits an indemnity agreement meeting the 
criteria in paragraph (e) of this section.
    (b) What to do if your guarantor becomes unqualified. If, during 
the life of your third-party guarantee, your guarantor no longer meets 
the criteria of paragraphs (a)(3) and (c)(3) of this section, you must:
    (1) Notify the Regional Director immediately; and
    (2) Cease production until you comply with the bond coverage 
requirements of this subpart.
    (c) Criteria for acceptable guarantees. If you propose to furnish a 
third party's guarantee, that guarantee must ensure compliance with all 
lessees' lease obligations, the obligations of all operating rights 
owners, and the obligations of all operators on the lease. The Regional 
Director will base acceptance of your third-party guarantee on the 
following criteria:
    (1) The period of time that your third-party guarantor (guarantor) 
has been in continuous operation as a business entity where:
    (i) Continuous operation is the time that your guarantor conducts 
business immediately before you post the guarantee; and
    (ii) Continuous operation excludes periods of interruption in 
operations that are beyond your guarantor's control and that do not 
affect your guarantor's likelihood of remaining in business during 
exploration, development, production, abandonment, and clearance 
operations on your lease.
    (2) Financial information available in the public record or 
submitted by your guarantor, on your guarantor's own initiative, in 
sufficient detail to show to the Regional Director's satisfaction that 
your guarantor is qualified based on:
    (i) Your guarantor's current rating for its most recent bond 
issuance by either Moody's Investor Service or Standard and Poor's 
Corporation;
    (ii) Your guarantor's net worth, taking into account liabilities 
under its guarantee of compliance with all the terms and conditions of 
your lease, the regulations in this chapter, and your guarantor's other 
guarantees;
    (iii) Your guarantor's ratio of current assets to current 
liabilities, taking into account liabilities under its guarantee of 
compliance with all the terms and conditions of your lease and the 
regulations in this chapter and your guarantor's other guarantees; and
    (iv) Your guarantor's unencumbered fixed assets in the United 
States.
    (3) When the information required by paragraph (c) of this section 
is not publicly available, your guarantor may submit the information in 
the following table. Your guarantor must update the information 
annually within 90 days of the end of the fiscal year or by the date 
prescribed by the Regional Director.

------------------------------------------------------------------------
     The guarantor should submit . . .               That . . .
------------------------------------------------------------------------
(i) Financial statements for the most       Include a report by an
 recently completed fiscal year,             independent certified
                                             public accountant
                                             containing the accountant's
                                             audit opinion or review
                                             opinion of the statements.
                                             The report must be prepared
                                             in conformance with
                                             generally accepted
                                             accounting principles and
                                             contain no adverse opinion.
(ii) Financial statements for completed     Your guarantor's financial
 quarters in the current fiscal year,        officer certifies to be
                                             correct.
(iii) Additional information as requested   Your guarantor's financial
 by the Regional Director,                   officer certifies to be
                                             correct.
------------------------------------------------------------------------

     (d) Provisions required in all third-party guarantees. Your third-
party guarantee must contain each of the following provisions.
    (1) If you, your operator, or an operating rights owner fails to 
comply with any lease term or regulation, your guarantor must either:
    (i) Take corrective action; or
    (ii) Be liable under the indemnity agreement to provide, within 7 
calendar days, sufficient funds for the Regional Director to complete 
corrective action.
    (2) If your guarantor complies with paragraph (d)(1) of this 
section, this compliance will not reduce its liability.
    (3) If your guarantor wishes to terminate the period of liability 
under its guarantee, it must:
    (i) Notify you and the Regional Director at least 90 days before 
the proposed termination date;
    (ii) Obtain the Regional Director's approval for the termination of 
the period of liability for all or a specified portion of your 
guarantor's guarantee; and
    (iii) Remain liable for all work and workmanship performed during 
the period that your guarantor's guarantee is in effect.
    (4) You must provide a suitable replacement security instrument 
before

[[Page 64694]]

the termination of the period of liability under your third-party 
guarantee.
    (e) Required criteria for indemnity agreements. If the Regional 
Director approves your third-party guarantee, the guarantor must submit 
an indemnity agreement.
    (1) The indemnity agreement must be executed by your guarantor and 
all persons and parties bound by the agreement.
    (2) The indemnity agreement must bind each person and party 
executing the agreement jointly and severally.
    (3) When a person or party bound by the indemnity agreement is a 
corporate entity, two corporate officers who are authorized to bind the 
corporation must sign the indemnity agreement.
    (4) Your guarantor and the other corporate entities bound by the 
indemnity agreement must provide the Regional Director copies of:
    (i) The authorization of the signatory corporate officials to bind 
their respective corporations;
    (ii) An affidavit certifying that the agreement is valid under all 
applicable laws; and
    (iii) Each corporation's corporate authorization to execute the 
indemnity agreement.
    (5) If your third-party guarantor or another party bound by the 
indemnity agreement is a partnership, joint venture, or syndicate, the 
indemnity agreement must:
    (i) Bind each partner or party who has a beneficial interest in 
your guarantor; and
    (ii) Provide that, upon demand by the Regional Director under your 
third-party guarantee, each partner is jointly and severally liable for 
compliance with all terms and conditions of your lease.
    (6) When forfeiture is called for under Sec.  556.59 of this part, 
the indemnity agreement must provide that your guarantor will either:
    (i) Bring your lease into compliance; or
    (ii) Provide, within 7 calendar days, sufficient funds to permit 
the Regional Director to complete corrective action.
    (7) The indemnity agreement must contain a confession of judgment. 
It must provide that, if the Regional Director determines that you, 
your operator, or an operating rights owner is in default of the lease, 
the guarantor:
    (i) Will not challenge the determination; and
    (ii) Will remedy the default.
    (8) Each indemnity agreement is deemed to contain all terms and 
conditions contained in this paragraph (e), even if the guarantor has 
omitted them.

Sec.  556.58  Termination of the period of liability and cancellation 
of a bond.

    This section defines the terms and conditions under which BOEM will 
terminate the period of liability of a bond or cancel a bond. 
Terminating the period of liability of a bond ends the period during 
which obligations continue to accrue but does not relieve the surety of 
the responsibility for obligations that accrued during the period of 
liability. Canceling a bond relieves the surety of all liability. The 
liabilities that accrue during a period of liability include 
obligations that started to accrue prior to the beginning of the period 
of liability and had not been met and obligations that begin accruing 
during the period of liability.
    (a) When the surety under your bond requests termination:
    (1) The Regional Director will terminate the period of liability 
under your bond within 90 days after BOEM receives the request; and
    (2) If you intend to continue operations, or have not met all end 
of lease obligations, you must provide a replacement bond of an 
equivalent amount.
    (b) If you provide a replacement bond, the Regional Director will 
cancel your previous bond and the surety that provided your previous 
bond will not retain any liability, provided that:
    (1) The new bond is equal to or greater than the bond that was 
terminated, or you provide an alternative form of security, and the 
Regional Director determines that the alternative form of security 
provides a level of security equal to or greater than that provided for 
by the bond that was terminated;
    (2) For a base bond submitted under Sec.  556.52(a) or under Sec.  
556.53(a) or (b), the surety issuing the new bond agrees to assume all 
outstanding liabilities that accrued during the period of liability 
that was terminated; and
    (3) For supplemental bonds submitted under Sec.  556.53(d), the 
surety issuing the new supplemental bond agrees to assume that portion 
of the outstanding liabilities that accrued during the period of 
liability which was terminated and that the Regional Director 
determines may exceed the coverage of the base bond, and of which the 
Regional Director notifies the provider of the bond.
    (c) This paragraph applies if the period of liability is terminated 
for a bond but the bond is not replaced by a bond of an equivalent 
amount. The surety that provided your terminated bond will continue to 
be responsible for accrued obligations:
    (1) Until the obligations are satisfied; and
    (2) For additional periods of time in accordance with paragraph (d) 
of this section.
    (d) When your lease expires or is terminated, the surety that 
issued a bond will continue to be responsible, and the Regional 
Director will retain other forms of security as shown in the following 
table:

------------------------------------------------------------------------
  For the following type of       The period of       Your bond will be
            bond               liability will end      cancelled . . .
------------------------------------------------------------------------
(1) Base bonds submitted      When the Regional     Seven years after
 under Sec.   556.52(a),       Director determines   the termination of
 Sec.   556.53(a), or (b),     that you have met     the lease, 6 years
                               all of your           after completion of
                               obligations under     all bonded
                               the lease,            obligations, or at
                                                     the conclusion of
                                                     any appeals or
                                                     litigation related
                                                     to your bonded
                                                     obligation,
                                                     whichever is the
                                                     latest. The
                                                     Regional Director
                                                     will reduce the
                                                     amount of your bond
                                                     or return a portion
                                                     of your security if
                                                     the Regional
                                                     Director determines
                                                     that you need less
                                                     than the full
                                                     amount of the base
                                                     bond to meet any
                                                     possible future
                                                     problems.
(2) Supplemental bonds        When the Regional     When you meet your
 submitted under Sec.          Director determines   bonded obligations,
 556.53(d),                    that you have met     unless the Regional
                               all your              Director:
                               obligations covered
                               by the supplemental
                               bond,
                                                    (i) Determines that
                                                     the future
                                                     potential liability
                                                     resulting from any
                                                     undetected problems
                                                     is greater than the
                                                     amount of the base
                                                     bond; and

[[Page 64695]]

 
                                                    (ii) Notifies the
                                                     provider of the
                                                     bond that the
                                                     Regional Director
                                                     will wait 7 years
                                                     before cancelling
                                                     all or a part of
                                                     the bond (or longer
                                                     period as necessary
                                                     to complete any
                                                     appeals or judicial
                                                     litigation related
                                                     to your bonding
                                                     obligation).
------------------------------------------------------------------------

     (e) For all bonds, the Regional Director may reinstate your bond 
as if no cancellation or release had occurred if:
    (1) A person makes a payment under the lease and the payment is 
rescinded or must be repaid by the recipient because the person making 
the payment is insolvent, bankrupt, subject to reorganization, or 
placed in receivership; or
    (2) The responsible party represents to BOEM that it has discharged 
its obligations under the lease, and the representation was materially 
false when the bond was canceled or released.

Sec.  556.59  Forfeiture of bonds and/or other securities.

    This section explains how a bond or other security may be 
forfeited.
    (a) The Regional Director will call for forfeiture of all or part 
of the bond, other form of security, or guarantee you provide under 
this part if:
    (1) You (the party who provided the bond) refuse, or the Regional 
Director determines that you are unable, to comply with any term or 
condition of your lease; or
    (2) You default under one of the conditions under which the 
Regional Director accepts your bond, third-party guarantee, and/or 
other form of security.
    (b) The Regional Director may pursue forfeiture of your bond 
without first making demands for performance against any lessee, 
operating rights owner, or other person authorized to perform lease 
obligations.
    (c) The Regional Director will:
    (1) Notify you, the surety on your bond or other form of security, 
and any third-party guarantor, of his/her determination to call for 
forfeiture of the bond, security, or guarantee under this section.
    (i) This notice will be in writing and will provide the reasons for 
the forfeiture and the amount to be forfeited.
    (ii) The Regional Director must base the amount he/she determines 
is forfeited upon his/her estimate of the total cost of corrective 
action to bring your lease into compliance.
    (2) Advise you, your third-party guarantor, and any surety, that 
you, your guarantor, and any surety may avoid forfeiture if, within 5 
working days:
    (i) You agree to, and demonstrate that you will, bring your lease 
into compliance within the timeframe that the Regional Director 
prescribes;
    (ii) Your third-party guarantor agrees to, and demonstrates that it 
will, complete the corrective action to bring your lease into 
compliance within the timeframe that the Regional Director prescribes; 
or
    (iii) Your surety agrees to, and demonstrates that it will, bring 
your lease into compliance within the timeframe that the Regional 
Director prescribes, even if the cost of compliance exceeds the face 
amount of the bond or other surety instrument.
    (d) If the Regional Director finds you are in default, he/she may 
cause the forfeiture of any bonds and other security deposited as your 
guarantee of compliance with the terms and conditions of your lease and 
the regulations in this chapter.
    (e) If the Regional Director determines that your bond and/or other 
security is forfeited, the Regional Director will:
    (1) Collect the forfeited amount; and
    (2) Use the funds collected to bring your leases into compliance 
and to correct any default.
    (f) If the amount the Regional Director collects under your bond 
and other security is insufficient to pay the full cost of corrective 
actions he/she may:
    (1) Take or direct action to obtain full compliance with your lease 
and the regulations in this chapter; and
    (2) Recover from you, any co-lessee, operating rights owner, and/or 
any third-party guarantor responsible under this subpart all costs in 
excess of the amount he/she collects under your forfeited bond and 
other security.
    (g) The amount that the Regional Director collects under your 
forfeited bond and other security may exceed the costs of taking the 
corrective actions required to obtain full compliance with the terms 
and conditions of your lease and the regulations in this chapter. In 
this case, the Regional Director will return the excess funds to the 
party from whom they were collected.

Subpart J--Assignments, Transfers, and Extensions

Sec.  556.62  Assignment of lease or interest in lease.

    This section explains how to assign record title and other 
interests in OCS oil and gas or sulphur leases.
    (a) BOEM may approve the assignment to you of the ownership of the 
record title to a lease or any undivided interest in a lease, or an 
officially designated subdivision of a lease, only if:
    (1) You qualify to hold a lease under Sec.  556.35(b);
    (2) You provide the bond coverage required under subpart I of this 
part; and
    (3) The Regional Director approves the assignment.
    (b) An assignment shall be void if it is made pursuant to any 
prelease agreement described in Sec.  556.44(c) of this part that would 
cause a bid to be disqualified.
    (c) Any approved assignment shall be deemed to be effective on the 
first day of the lease month following its filing in the appropriate 
office of the BOEM, unless at the request of the parties, an earlier 
date is specified in the approval.
    (d) You, as assignor, are liable for all obligations that accrue 
under your lease before the date that the Regional Director approves 
your request for assignment of the record title in the lease. The 
Regional Director's approval of the assignment does not relieve you of 
accrued lease obligations that your assignee, or a subsequent assignee, 
fails to perform.
    (e) Your assignee and each subsequent assignee are liable for all 
obligations that accrue under the lease after the date that the 
Regional Director approves the governing assignment. They must:
    (1) Comply with all the terms and conditions of the lease and all 
regulations issued under the Act; and
    (2) Remedy all existing environmental problems on the tract, 
properly abandon all wells, and reclaim the lease site in accordance 
with 30 CFR part 250, subpart Q.
    (f) If your assignee, or a subsequent assignee, fails to perform 
any obligation under the lease or the regulations in this chapter, the 
Regional Director may

[[Page 64696]]

require you to bring the lease into compliance to the extent that the 
obligation accrued before the Regional Director approved the assignment 
of your interest in the lease.

Sec.  556.63  Service fees.

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

                            Service Fee Table
------------------------------------------------------------------------
            Service                Fee amount        30 CFR citation
------------------------------------------------------------------------
(1) Record Title/Operating                 $186  Sec.   556.64
 Rights (Transfer).
(2) Non-required Document                    27  Sec.   556.64
 Filing.
------------------------------------------------------------------------

     (b) 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 
with the amended application.

Sec.  556.64  How to file transfers.

    This section explains how to file instruments with BOEM that create 
and/or transfer interests in OCS oil and gas or sulphur leases.
    (a) You must submit to the Regional Director for approval all 
instruments that create or transfer ownership of a lease interest.
    (1) You must submit two copies of the instruments that create or 
transfer an interest. Each instrument that creates or transfers an 
interest must describe by officially designated subdivision the 
interest you propose to create or transfer.
    (2) You must submit your proposal to create or transfer an 
interest, or create or transfer separate operating rights, subleases, 
and record title interests within 90 days of the last date that a party 
executes the transfer agreement.
    (3) The transferee must meet the citizenship and other 
qualification criteria specified in Sec.  556.35 of this part. When you 
submit an instrument to create or transfer an interest as an 
association, you must include a statement signed by the transferee 
about the transferee's citizenship and qualifications to own a lease.
    (4) Your instrument to create or transfer an interest must contain 
all of the terms and conditions to which you and the other parties 
agree.
    (5) You do not gain a release of any nonmonetary obligation under 
your lease or the regulations in this chapter by creating a sublease or 
transferring operating rights.
    (6) You do not gain a release from any accrued obligation under 
your lease or the regulations in this chapter by assigning your record 
title interest in the lease.
    (7) You may create or transfer carried working interests, 
overriding royalty interests, or payments out of production without 
obtaining the Regional Director's approval. However, you must file 
instruments creating or transferring carried working interests, 
overriding royalty interests, or payments out of production with the 
Regional Director for record purposes.
    (8) You must pay electronically through Pay.gov at: https://www.pay.gov/paygov/ the service fee listed in Sec.  556.63 of this 
subpart and you must include a copy of the Pay.gov confirmation receipt 
page with your application for approval of any instrument of transfer 
you are required to file (Record Title and/or Operating Rights 
(Transfer) Fee). Where multiple transfers of interest are included in a 
single instrument, a separate fee applies to each individual transfer 
of interest. For any document you are not required to file by these 
regulations but which you submit for record purposes, you must also pay 
electronically through Pay.gov the service fee listed in Sec.  556.63 
(Non-required Document Filing Fee) per lease affected, and you must 
include a copy of the Pay.gov confirmation receipt page with your 
document. Such documents may be rejected at the discretion of the 
authorized officer.
    (b) An attorney in fact, in behalf of the holder of a lease, 
operating rights or sublease, shall furnish evidence of authority to 
execute the assignment or application for approval and the statement 
required by Sec.  556.46 of this part.
    (c) When you request approval for an assignment that assigns all 
your record title interest in a lease or that creates a segregated 
lease, your assignee must furnish a bond in the amount prescribed in 
Sec. Sec.  556.52 and 556.53 of this part.
    (d) When you request approval for an assignment that assigns less 
than all the record title of a lease and that does not create a 
separate lease, the assignee may, with the surety's consent, become a 
joint principal on the surety instrument that guarantees compliance 
with all the terms and conditions of the lease.
    (e) An heir or devisee of a deceased holder of a lease, or any 
interest therein, shall be recognized as the lawful successor to such 
lease or interest, if evidence of status as an heir or devisee is 
furnished in the form of:
    (1) A certified copy of an appropriate order or decree of the court 
having jurisdiction of the distribution of the estate or,
    (2) If no court action is necessary, the statements of two 
disinterested parties having knowledge of the facts or a certified copy 
of the will.
    (f) In addition to the requirements of paragraph (d) of this 
section, the heirs or devisees shall file statements that they are the 
persons named as successors to the estate with evidence of their 
qualifications as provided in Sec.  556.46 of this part.
    (g) In the event an heir or devisee is unable to qualify to hold 
the lease or interest, the heir or devisee shall be recognized as the 
lawful successor of the deceased and be entitled to hold the lease for 
a period of not to exceed 2 years from the date of death of the 
predecessor in interest.
    (h) Your heirs, executors, administrators, successors, and assigns 
are bound to comply with each obligation under any lease and under the 
regulations in this chapter.
    (1) You are jointly and severally liable for the performance of 
each nonmonetary obligation under the lease and under the regulations 
in this chapter with each prior lessee and with each operating rights 
owner holding an interest at the time the obligation accrued, unless 
this chapter provides otherwise.
    (2) Sublessees and operating rights owners are jointly and 
severally liable for the performance of each nonmonetary obligation 
under the lease and under the regulations in this chapter to the extent 
that:

[[Page 64697]]

    (i) The obligation relates to the area embraced by the sublease;
    (ii) Those owners held their respective interest at the time the 
obligation accrued; and
    (iii) This chapter does not provide otherwise.
    (i) Where the proposed assignment or transfer is by a person who, 
at the time of acquisition of an interest in the lease, was on the List 
of Restricted Joint Bidders, and that assignment or transfer is of less 
than the entire interest of the assignor or transferor, to a person or 
persons on the same List of Restricted Joint Bidders, the assignor or 
transferor shall file a copy, prior to approval of the assignment, of 
all agreements applicable to the acquisition of that lease or a 
fractional interest.

Sec.  556.65  Attorney General review.

    Prior to the approval of an assignment or transfer, the Secretary 
shall consult with and give due consideration to the views of the 
Attorney General. The Secretary may act on an assignment or transfer if 
the Attorney General has not responded to the request for consultation 
within 30 days of said request.

Sec.  556.67  Separate filings for assignments.

    A separate instrument of assignment shall be filed for each lease. 
When transfers to the same person, association or corporation, 
involving more than one lease are filed at the same time for approval, 
one request for approval and one showing as to the qualifications of 
the assignee shall be sufficient.

Sec.  556.68  Effect of assignment of a particular tract.

    (a) When an assignment is made of all the record title to a portion 
of the acreage in a lease, the assigned and retained portions become 
segregated into separate and distinct leases. In such a case, the 
assignee becomes a lessee of the Government as to the segregated tract 
that is the subject of assignment, and is bound by the terms of the 
lease as though the lease had been obtained from the United States in 
the assignee's own name, and the assignment, after its approval, shall 
be the basis of a new record. Royalty, minimum royalty and rental 
provisions of the original lease shall apply separately to each 
segregated portion.
    (b) For assignments of a portion of an oil and gas lease approved 
after the effective date of this section, each segregated lease shall 
continue in full force and effect for the primary term of the original 
lease and so long thereafter as oil or gas is produced from that 
segregated portion of the leased area in paying quantities or drilling 
or well reworking operations as approved by the Secretary are 
conducted.
    (c) For those assignments approved prior to the effective date of 
this section, each segregated lease shall continue in full force and 
effect for the primary term of the original lease and so long 
thereafter as oil and gas may be produced from the original leased area 
in paying quantities or drilling or well reworking operations, as 
approved by the Secretary, are conducted.

Sec.  556.70  Extension of lease by drilling or well reworking 
operations.

    The term of a lease shall be extended beyond the primary term so 
long as drilling or well reworking operations are approved by the 
Secretary according to the conditions set forth in 30 CFR 250.180.

Sec.  556.71  Directional drilling.

    In accordance with an approved exploration plan or development and 
production plan, a lease may be maintained in force by directional 
wells drilled under the leased area from surface locations on adjacent 
or adjoining land not covered by the lease. In such circumstances, 
drilling shall be considered to have commenced on the leased area when 
drilling is commenced on the adjacent or adjoining land for the purpose 
of directional drilling under the leased area through any directional 
well surfaced on adjacent or adjoining land. Production, drilling, or 
reworking of any such directional well shall be considered production 
or drilling or reworking operations on the leased area for all purposes 
of the lease.

Sec.  556.72  Compensatory payments as production.

    If an oil and gas lessee makes compensatory payments and if the 
lease is not being maintained in force by other production of oil or 
gas in paying quantities or by other approved drilling or reworking 
operations, such payments shall be considered as the equivalent of 
production in paying quantities for all purposes of the lease.

Subpart K--Termination of Leases

Sec.  556.76  Relinquishment of leases or parts of leases.

    A lease or any officially designated subdivision thereof may be 
surrendered by the record title holder by filing a written 
relinquishment, in triplicate, with the appropriate OCS office of the 
BOEM. No filing fee is required. A relinquishment shall take effect on 
the date it is filed subject to the continued obligation of the lessee 
and the surety to make all payments due, including any accrued rentals, 
royalties and deferred bonuses and to abandon all wells and condition 
or remove all platforms and other facilities on the land to be 
relinquished to the satisfaction of the Director.

Sec.  556.77  Cancellation of leases.

    (a) Any nonproducing lease issued under the act may be cancelled by 
the authorized officer whenever the lessee fails to comply with any 
provision of the act or lease or applicable regulations, if such 
failure to comply continues for 30 days after mailing of notice by 
registered or certified letter to the lease owner at the owner's record 
post office address. Any such cancellation is subject to judicial 
review as provided in section 23(b) of the Act.
    (b) Producing leases issued under the Act may be cancelled by the 
Secretary whenever the lessee fails to comply with any provision of the 
Act, applicable regulations or the lease only after judicial 
proceedings as prescribed by section 5(d) of the Act.
    (c) Any lease issued under the Act, whether producing or not, shall 
be canceled by the authorized officer upon proof that it was obtained 
by fraud or misrepresentation, and after notice and opportunity to be 
heard has been afforded to the lessee.
    (d) Pursuant to section 5(a) of the Act, the Secretary may cancel a 
lease when:
    (1) Continued activity pursuant to such lease would probably cause 
serious harm or damage to life, property, any mineral, National 
security or defense, or to the marine, coastal or human environment;
    (2) The threat of harm or damage will not disappear or decrease to 
an acceptable extent within a reasonable period of time; and
    (3) The advantages of cancellation outweigh the advantages of 
continuing such lease or permit in force. Procedures and conditions 
contained in Sec.  550.182 shall apply as appropriate.

Subpart L--Section 6 Leases

Sec.  556.79  Effect of regulations on lease.

    (a) All regulations in this part, insofar as they are applicable, 
shall supersede the provisions of any lease which is maintained under 
section 6(a) of the Act. However, the provisions of a lease relating to 
area, minerals, rentals, royalties (subject to sections 6(a) (8) and 
(9) of the Act), and term (subject to section 6(a)(10) of the Act and, 
as to sulfur, subject to section 6(b)(2) of the Act) shall continue in 
effect, and, in the event of any conflict or inconsistency, shall take 
precedence over these regulations.

[[Page 64698]]

    (b) A lease maintained under section 6(a) of the Act shall also be 
subject to all operating and conservation regulations applicable to the 
OCS. In addition, the regulations relating to geophysical and 
geological exploratory operations and to pipeline rights-of-way are 
applicable, to the extent that those regulations are not contrary to or 
inconsistent with the lease provisions relating to area, the minerals, 
rentals, royalties and term. The lessee shall comply with any provision 
of the lease as validated, the subject matter of which is not covered 
in the regulations in this part.

Sec.  556.80  Leases of other minerals.

    The existence of a lease that meets the requirements of section 
6(a) of the Act shall not preclude the issuance of other leases of the 
same area for deposits of other minerals. However, no other lease of 
minerals shall authorize or permit the lessee thereunder unreasonably 
to interfere with or endanger operations under the existing lease. No 
sulphur leases shall be granted by the United States on any area while 
such area is included in a lease covering sulphur under section 6(b) of 
the Act.

Subpart M--Studies

Sec.  556.82  Environmental studies.

    (a) The Director shall conduct a study of any area or region 
included in any lease sale in order to establish information needed for 
assessment and management of impacts on the human, marine and coastal 
environments which may be affected by OCS oil and gas activities in 
such area or region. Any study shall, to the extent practicable, be 
designed to predict environmental impacts of pollutants introduced into 
the environments and of the impacts of offshore activities on the 
seabed and affected coastal areas.
    (b) Studies shall be planned and carried out in cooperation with 
the affected States and interested parties and, to the extent possible, 
shall not duplicate studies done under other laws. Where appropriate, 
the Director shall, to the maximum extent practicable, enter into 
agreements with the National Oceanic and Atmospheric Administration in 
executing the environmental studies responsibilities. By agreement, the 
Director may also utilize services, personnel or facilities of any 
Federal, State or local government agency in the conduct of such study.
    (c) Any study of an area or region required by paragraph (a) of 
this section for a lease sale shall be commenced not later than 6 
months prior to holding a lease sale for that area. The Director may 
utilize information collected in any prior study. The Director may 
initiate studies for areas or regions not identified in the leasing 
program.
    (d) After the leasing and developing of any area or region, the 
Director shall conduct such studies as are deemed necessary to 
establish additional information and shall monitor the human, marine 
and coastal environments of such area or region in a manner designed to 
provide information which can be compared with the results of studies 
conducted prior to OCS oil and gas development. This shall be done to 
identify any significant changes in the quality and productivity of 
such environments, to establish trends in the areas studies, and to 
design experiments identifying the causes of such changes. Findings 
from such studies shall be used to recommend modifications in practices 
which are employed to mitigate the effects of OCS activities and to 
enhance the data/information base for predicting impacts which might 
result from a single lease sale or cumulative OCS activities.
    (e) Information available or collected by the studies program 
shall, to the extent practicable, be provided in a form and in a 
timeframe that can be used in the decision-making process associated 
with a specific leasing action or with longer term OCS minerals 
management responsibilities.

Subpart N--Bonus or Royalty Credits for Exchange of Certain Leases 
Offshore Florida

Sec.  556.90  Which leases may I exchange for a bonus or royalty 
credit?

    You may exchange a lease for a bonus or royalty credit if it:
    (a) Was in effect on December 20, 2006, and
    (b) Is located in:
    (1) The Eastern planning area and within 125 miles of the coastline 
of the State of Florida, or
    (2) The Central planning area and within the Desoto Canyon OPD, the 
Destin Dome OPD, or the Pensacola OPD, and within 100 miles of the 
coastline of the State of Florida.

Sec.  556.91  How much bonus or royalty credit will BOEM grant in 
exchange for a lease?

    The amount of the bonus or royalty credit for an exchanged lease 
equals the sum of:
    (a) The amount of the bonus payment; and
    (b) All rent paid for the lease as of the date the lessee submits 
the request to exchange the lease under Sec.  556.92 to BOEM.

Sec.  556.92  What must I do to obtain a bonus or royalty credit?

    (a) To obtain the bonus or royalty credit, all of the record title 
interest owners in the lease must submit the following to the BOEM 
Regional Supervisor for Leasing and Environment for the Gulf of Mexico 
on or before October 14, 2010.
    (1) A written request to exchange the lease for the bonus or 
royalty credit, signed by all record title interest owners in the 
lease.
    (2) The name and contact information for a person who will act as a 
contact for each record title interest owner.
    (3) Documentation of each record title interest owner's percentage 
share in the lease.
    (4) A list of all bonus and rental payments for that lease made by, 
or on behalf of, each of the current record title owners.
    (5) A written relinquishment of the lease as described in Sec.  
556.76. Notwithstanding Sec.  556.76, the relinquishment will become 
effective when the credit becomes effective under paragraph (b) of this 
section.
    (b) The credit becomes effective when BOEM issues a certification 
to the record title interest owners that the lease has qualified for 
the credit and when ONRR issues the credit.

Sec.  556.93  How is the bonus or royalty credit allocated among 
multiple lease owners?

    BOEM will allocate the bonus or royalty credit for an exchanged 
lease to the current record title interest owners in the same 
percentage share as each owner has in the lease as of the date of the 
request to exchange the lease.

Sec.  556.94  How may I use the bonus or royalty credit?

    (a) You may use a credit issued under this part in lieu of a 
monetary payment due under any lease in the Gulf of Mexico not subject 
to the revenue distribution provisions of section 8(g)(2) of the OCSLA 
(43 U.S.C. 1337(g)(2)) for either:
    (1) A bonus for acquisition of an interest in a new lease; or
    (2) Royalty due on oil and gas production after October 14, 2008.
    (b) You may not use a bonus or royalty credit in lieu of delivering 
oil or gas taken as royalty-in-kind.
    (c) If you have any credit that remains unused after 5 years from 
the date ONRR issued the credit, ONRR reserves the right to apply the 
remaining credit to any of your obligations.

Sec.  556.95  How do I transfer a bonus or royalty credit to another 
person?

    (a) You may transfer your bonus or royalty credit to any other 
person by

[[Page 64699]]

submitting to the BOEM Adjudication Unit for the Gulf of Mexico two 
originally executed transfer letters of agreement.
    (b) Authorized officers indicated on the qualification card filed 
with BOEM of all companies involved in transferring and receiving the 
credit must sign the transfer letters of agreement.
    (c) A transfer letter of agreement must include:
    (1) The effective date of the transfer,
    (2) The OCS-G number for the lease that originally qualified for 
the credit,
    (3) The amount of the credit being transferred,
    (4) Company names punctuated exactly as filed on the qualification 
card at BOEM, and
    (5) A corporate seal, if you used a corporate seal in your initial 
qualification to hold OCS leases.
    (d) The transferee of a credit transferred under this section may 
use it in accordance with Sec.  556.94 as soon as BOEM sends a 
confirmation of the transfer to the transferee.

Appendix to Part 556--Oil and Gas Cash Bonus Bid

    The following bid is submitted for an oil and gas lease on the 
area of the Outer Continental Shelf specified below:

------------------------------------------------------------------------
                                                         Amount of cash
    Tract No.*      Total amount bid   Amount per acre   submitted  with
                                      (or per hectare)         bid
------------------------------------------------------------------------
 
------------------------------------------------------------------------
 * Or, if tract numbers are not used, Protraction Diagram or Leasing Map
  and block number.

----------------------------------------------------------------------------------------------------------------
                                      Proportionate interest of company(s)
      Bidder qualification No.                    submitting bid             Name and address of bidding company
----------------------------------------------------------------------------------------------------------------
---- Misc. No.                        ....................................  ....................................
----------------------------------------------------------------------------------------------------------------

----------------------------------------,

    Authorized signatory's name and title.

PART 559--MINERAL LEASING: DEFINITIONS

Sec.
559.001 Purpose and scope.
559.002 Definitions.

    Authority: Pub. L. 83-212, 67 Stat. 462, 43 U.S.C. 1331 et seq., 
as amended by Pub. L. 95-372, 92 Stat. 629.

Sec.  559.001  Purpose and scope.

    The purpose of this part 559 is to define various terms appearing 
in part 560.

Sec.  559.002  Definitions.

    For purposes of part 560:
    Area or region means the geographic area or region over which the 
BOEM designated official has jurisdiction, unless the context in which 
those words are used indicates that a different meaning is intended.
    BOEM means Bureau of Ocean Energy Management.
    Designated official means a representative of DOI subject to the 
direction and supervisory authority of the Directors, BOEM, and the 
appropriate Regional Manager of the BOEM authorized and empowered to 
supervise and direct all oil and gas operations and to perform other 
duties prescribed in this chapter.
    Director means Director, BOEM, DOI.
    DOI means the Department of the Interior, including the Secretary 
of the Interior, or his or her delegate.
    Federal lease means an agreement which, for any consideration, 
including, but not limited to, bonuses, rents or royalties conferred, 
and convenants to be observed, authorizes a person to explore for, or 
develop, or produce (or to do any or all of these) oil and gas, coal, 
oil shale, tar sands, and geothermal resources on lands or interests in 
lands under Federal jurisdiction.
    Gas means natural gas as defined by the Federal Energy Regulatory 
Commission.
    OCS means the Outer Continental Shelf, which includes all submerged 
lands (1) that lie seaward outside of the area of lands beneath 
navigable waters as defined in the Submerged Lands Act (Pub. L. 31-35, 
67 Stat. 29, (43 U.S.C. 1301)) and (2) of which the subsoil and seabed 
appertain to the United States are subject to its jurisdiction and 
control.
    OCSLA means the Outer Continental Shelf Lands Act, as amended (Act 
of August 7, 1953, Ch. 345, 67 Stat. 462, 43 U.S.C. 1331 et seq., as 
amended by Pub. L. 95-372, 92 Stat. 629).
    Oil means a mixture of hydrocarbons that exists in a liquid or 
gaseous phase in an underground reservoir and which remains or becomes 
liquid at atmospheric pressure after passing through surface separating 
facilities, including condensate recovered by means other than a 
manufacturing process.

PART 560--OUTER CONTINENTAL SHELF OIL AND GAS LEASING

Subpart A--General Provisions
Sec.
560.1 What is the purpose of this part?
560.2 What definitions apply to this part?
560.3 What is BOEM's authority to collect information?
Subpart B--Bidding Systems

General Provisions

560.101 What is the purpose of this subpart?
560.102 What definitions apply to this subpart?
560.110 What bidding systems may BOEM use?
560.111 What conditions apply to the bidding systems that BOEM uses?

Eligible Leases

560.112 How do royalty suspension volumes apply to eligible leases?
560.113 When does an eligible lease qualify for a royalty suspension 
volume?
560.114 How does BOEM assign and monitor royalty suspension volumes 
for eligible leases?
560.115 How long will a royalty suspension volume for an eligible 
lease be effective?
560.116 How do I measure natural gas production on my eligible 
lease?

Royalty Suspensions (RS) Leases

560.120 How does royalty suspension apply to leases issued in a sale 
held after November 2000?
560.121 When does a lease issued in a sale held after November 2000 
get a royalty suspension?
560.122 How long will a royalty suspension volume be effective for a 
lease issued in a sale held after November 2000?
560.123 How do I measure natural gas production for a lease issued 
in a sale held after November 2000?
560.124 How will royalty suspension apply if BOEM assigns a lease 
issued in a sale held after November 2000 to a field that has a pre-
Act lease?

Bidding System Selection Criteria

560.130 What criteria does BOEM use for selecting bidding systems 
and bidding system components?

[[Page 64700]]

Subpart C--[Reserved]
Subpart D--Joint Bidding
560.301 What is the purpose of this subpart?
560.302 What definitions apply to this subpart?
560.303 What are the joint bidding requirements?

    Authority:  43 U.S.C. 1331 et seq.

Subpart A--General Provisions

Sec.  560.1  What is the purpose of this part?

    This part 560 implements the Outer Continental Shelf Lands Act 
(OCSLA), 43 U.S.C. 1331 et seq., as amended, by providing regulations 
to foster competition including, but not limited to:
    (a) Implementing alternative bidding systems;
    (b) Prohibiting joint bidding for development rights by certain 
types of joint ventures; and
    (c) Establishing diligence requirements for Federal OCS leases.

Sec.  560.2  What definitions apply to this part?

    OCS lease means a Federal lease for oil and gas issued under the 
OCSLA.
    OCSLA means the Outer Continental Shelf Lands Act, (43 U.S.C. 1331 
et seq.), as amended.
    Person includes, in addition to a natural person, an association, a 
State, or a private, public, or municipal corporation.
    We means the Bureau of Ocean Energy Management (BOEM).
    You means the lessee or operating rights holder.

Sec.  560.3  What is BOEM's authority to collect information?

    (a) The Paperwork Reduction Act of 1995 (PRA) requires us to inform 
you that we may not conduct or sponsor, and you are not required to 
respond to, a collection of information unless it displays a currently 
valid OMB control number. The information collection under 30 CFR part 
560 is either exempt from the PRA (5 CFR 1320.4(a)(2), (c)) or refers 
to requirements covered under 30 CFR parts 203 and 556.
    (b) You may send comments regarding any aspect of the collection of 
information under this part to the Information Collection Clearance 
Officer, Bureau of Ocean Energy Management, 381 Elden Street, Herndon, 
VA 20170.

Subpart B--Bidding Systems

General Provisions

Sec.  560.101  What is the purpose of this subpart?

    This subpart establishes the bidding systems that we may use to 
offer and sell Federal leases for the exploration, development, and 
production of oil and gas resources located on the OCS.

Sec.  560.102  What definitions apply to this subpart?

    Act means the Outer Continental Shelf Deep Water Royalty Relief 
Act, Pub. L. 104-58, 43 U.S.C. 1337(3).
    Eligible lease means a lease that:
    (1) Is issued as part of an OCS lease sale held after November 28, 
1995, and before November 28, 2000;
    (2) Is located in the Gulf of Mexico in water depths of 200 meters 
or deeper;
    (3) Lies wholly west of 87 degrees, 30 minutes West longitude; and
    (4) Is offered subject to a royalty suspension volume.
    Field means an area consisting of a single reservoir or multiple 
reservoirs all grouped on, or related to, the same general geological 
structural feature and/or stratigraphic trapping condition. Two or more 
reservoirs may be in a field, separated vertically by intervening 
impervious strata, or laterally by local geologic barriers, or by both.
    Highest responsible qualified bidder means a person who has met the 
appropriate requirements of 30 CFR part 556, subpart G, and has 
submitted a bid higher than any other bids by qualified bidders on the 
same tract.
    Highest royalty rate means the highest percent rate payable to the 
United States, as specified in the lease, in the amount or value of the 
production saved, removed, or sold.
    Lease period means the time from lease issuance until 
relinquishment, expiration, or termination.
    Lowest royalty rate means the lowest percent rate payable to the 
United States, as specified in the lease, in the amount or value of the 
production saved, removed, or sold.
    OCS lease sale means the Department of the Interior (DOI) 
proceeding by which leases for certain OCS tracts are offered for sale 
by competitive bidding and during which bids are received, announced, 
and recorded.
    Pre-Act lease means a lease that:
    (1) Is issued as part of an OCS lease sale held before November 28, 
1995;
    (2) Is located in the Gulf of Mexico in water depths of 200 meters 
or deeper; and
    (3) Lies wholly west of 87 degrees, 30 minutes West longitude (see 
30 CFR part 203).
    Production period means the period during which the amount of oil 
and gas produced from a tract (or, if the tract is unitized, the amount 
of oil and gas as allocated under a unitization formula) will be 
measured for purposes of determining the amount of royalty payable to 
the United States.
    Qualified bidder means a person who has met the appropriate 
requirements of 30 CFR part 556, subpart G.
    Royalty rate means the percentage of the amount or value of the 
production saved, removed, or sold that is due and payable to the 
United States Government.
    Royalty suspension (RS) lease means a lease that:
    (1) Is issued as part of an OCS lease sale held after November 28, 
2000;
    (2) Is in locations or planning areas specified in a particular 
Notice of OCS Lease Sale; and
    (3) Is offered subject to a royalty suspension specified in a 
Notice of OCS Lease Sale published in the Federal Register.
    Tract means a designation assigned solely for administrative 
purposes to a block or combination of blocks that are identified by a 
leasing map or an official protraction diagram prepared by the DOI.
    Value of production means the value of all oil and gas production 
saved, removed, or sold from a tract (or, if the tract is unitized, the 
value of all oil and gas production saved, removed, or sold and 
credited to the tract under a unitization formula) during a period of 
production. The value of production is determined under 30 CFR part 
1206.

Sec.  560.110  What bidding systems may BOEM use?

    We will apply a single bidding system selected from those listed in 
this section to each tract included in an OCS lease sale. The following 
table lists bidding systems, the bid variables, and characteristics.

------------------------------------------------------------------------
For the bidding system   The bid variable is    And the characteristics
         . . .                the . . .                are . . .
------------------------------------------------------------------------
(a) Cash bonus bid      Cash bonus,            The highest responsible
 with a fixed royalty                           qualified bidder will
 rate of not less than                          pay a royalty rate of
 12.5 percent,                                  not less than 12.5
                                                percent at the beginning
                                                of the lease period. We
                                                will specify the royalty
                                                rate for each tract
                                                offered in the Notice of
                                                OCS Lease Sale published
                                                in the Federal Register.

[[Page 64701]]

 
(b) Royalty rate bid    Royalty rate,          We will specify the fixed
 with fixed cash                                amount of cash bonus the
 bonus,                                         highest responsible
                                                qualified bidder must
                                                pay in the Notice of OCS
                                                Lease Sale published in
                                                the Federal Register.
(c) Cash bonus bid      Cash bonus,            (1) We will calculate the
 with a sliding                                 royalty rate the highest
 royalty rate of not                            responsible qualified
 less than 12.5                                 bidder must pay using
 percent at the                                 either:
 beginning of the                              (i) A sliding-scale
 lease period,                                  formula, which relates
                                                the royalty rate to the
                                                adjusted value or volume
                                                of production, or
                                               (ii) A schedule that
                                                establishes the royalty
                                                rate that we will apply
                                                to specified ranges of
                                                the adjusted value or
                                                volume of production.
                                               (2) We will determine the
                                                adjusted value of
                                                production by applying
                                                an inflation factor to
                                                the actual value of
                                                production.
                                               (3) If you are the
                                                successful high bidder,
                                                your lease will include
                                                the sliding-scale
                                                formula or schedule and
                                                will specify the lowest
                                                and highest royalty
                                                rates that will apply.
                                               (4) You will pay a
                                                royalty rate of not less
                                                than 12.5 percent at the
                                                beginning of the lease
                                                period.
                                               (5) We will include the
                                                sliding-scale royalty
                                                formula or schedule,
                                                inflation factor and
                                                procedures for making
                                                the inflation adjustment
                                                and determining the
                                                value or amount of
                                                production in the Notice
                                                of OCS Lease Sale
                                                published in the Federal
                                                Register.
(d) Cash bonus bid      Cash bonus,            (1) If we award you a
 with fixed share of                            lease as the highest
 the net profits of no                          responsible qualified
 less than 30 percent,                          bidder, you will
                                                determine the amount of
                                                the net profit share
                                                payment to the United
                                                States for each month by
                                                multiplying the net
                                                profit share base times
                                                the net profit share
                                                rate, according to 30
                                                CFR 1220.022. You will
                                                calculate the net profit
                                                share base according to
                                                30 CFR 1220.021.
                                               (2) You will pay a net
                                                profit share of not less
                                                than 30 percent.
                                               (3) We will specify the
                                                capital recovery factor,
                                                as described in 30 CFR
                                                1220.020, and the net
                                                profit share rate, both
                                                of which may vary from
                                                tract to tract, in the
                                                Notice of OCS Lease Sale
                                                published in the Federal
                                                Register.
(e) Cash bonus with     Cash bonus,            (1) We may suspend or
 variable royalty                               defer royalty for a
 rate(s) during one or                          period, volume, or value
 more periods of                                of production.
 production,                                    Notwithstanding
                                                suspensions or
                                                deferrals, we may impose
                                                a minimum royalty. The
                                                suspensions or deferrals
                                                may vary based on prices
                                                or price changes of oil
                                                and/or gas.
                                               (2) You may pay a royalty
                                                rate less than 12.5
                                                percent on production
                                                but not less than zero
                                                percent.
                                               (3) We will specify the
                                                applicable royalty
                                                rates(s) and suspension
                                                or deferral magnitudes,
                                                formulas, or
                                                relationships in the
                                                Notice of OCS Lease Sale
                                                published in the Federal
                                                Register.
(f) Cash bonus with     Cash bonus,            We will base the royalty
 royalty rate(s) based                          rate on formula(s) or
 on formula(s) or                               schedule(s) specified in
 schedule(s) during                             the Notice of OCS Lease
 one or more periods                            Sale published in the
 of production,                                 Federal Register.
(g) Cash bonus with a   Cash bonus,            Except for periods of
 fixed royalty rate of                          royalty suspension, you
 not less than 12.5                             will pay a fixed royalty
 percent, at the                                rate of not less than
 beginning of the                               12.5 percent. If we
 lease period,                                  award to you a lease
 suspension of                                  under this system, you
 royalties for a                                must calculate the
 period, volume, or                             royalty due during the
 value of production,                           designated period using
 or depending upon                              the rate, formula, or
 selected                                       schedule specified in
 characteristics of                             the lease. We will
 extraction, and with                           specify the royalty
 suspensions that may                           rate, formula, or
 vary based on the                              schedule in the Notice
 price of production,                           of OCS Lease Sale
                                                published in the Federal
                                                Register.
------------------------------------------------------------------------

Sec.  560.111  What conditions apply to the bidding systems that BOEM 
uses?

    (a) For each of the bidding systems in Sec.  560.110, we will 
include an annual rental fee. Other fees and provisions may apply as 
well. The Notice of OCS Lease Sale published in the Federal Register 
will specify the annual rental and any other fees the highest 
responsible qualified bidder must pay and any other provisions.
    (b) If we use any deferment or schedule of payments for the cash 
bonus bid, we will specify and include it in the Notice of OCS Lease 
Sale published in the Federal Register.
    (c) For the bidding systems listed in this subpart, if the bid 
variable is a cash bonus bid, the highest bid by a qualified bidder 
determines the amount of cash bonus to be paid. We will include the 
minimum bid level(s) in the Notice of OCS Lease Sale published in the 
Federal Register.
    (d) For the bidding systems listed in this subpart, if the bid 
variable is the royalty rate, the highest bid by a qualified bidder 
determines the royalty rate to be paid. We will include the minimum 
royalty rate(s) in the Notice of OCS Lease Sale published in the 
Federal Register.
    (e) We may, by rule, add to or modify the bidding systems listed in 
Sec.  560.110, according to the procedural requirements of the OCSLA, 
43 U.S.C. 1331 et seq., as amended by Public Law 95-372, 92 Stat. 629.

Eligible Leases

Sec.  560.112  How do royalty suspension volumes apply to eligible 
leases?

    Royalty suspension volumes, as specified in section 304 of the Act,

[[Page 64702]]

apply to eligible leases that meet the criteria in Sec.  560.113. For 
purposes of this section and Sec. Sec.  560.113 through 560.117:
    (a) Any volumes of production that are not normally royalty-bearing 
under the lease or the regulations (e.g., fuel gas) do not count 
against royalty suspension volumes; and
    (b) Production includes volumes allocated to a lease under an 
approved unit agreement.

Sec.  560.113  When does an eligible lease qualify for a royalty 
suspension volume?

    (a) Your eligible lease will receive a royalty suspension volume as 
specified in the Act. The bidding system in Sec.  560.110(g) applies.
    (b) Your eligible lease may receive a royalty suspension volume 
only if your entire lease is west of 87 degrees, 30 minutes West 
longitude.

Sec.  560.114  How does BOEM assign and monitor royalty suspension 
volumes for eligible leases?

    (a) We have specified the water depth category for each eligible 
lease in the final Notice of OCS Lease Sale Package. The Final Notice 
of Sale is published in the Federal Register and the complete Final 
Notice of OCS Lease Sale Package is available on the BOEM Web site. Our 
determination of water depth for each lease became final when we issued 
the lease.
    (b) We have specified in the Notice of OCS Lease Sale the royalty 
suspension volume applicable to each water depth. The following table 
shows the royalty suspension volumes for each eligible lease in million 
barrels of oil equivalent (MMBOE):

------------------------------------------------------------------------
             Water depth               Minimum royalty suspension volume
------------------------------------------------------------------------
(1) 200 to less than 400 meters......  17.5 MMBOE.
(2) 400 to less than 800 meters......  52.5 MMBOE.
(3) 800 meters or more...............  87.5 MMBOE.
------------------------------------------------------------------------

Sec.  560.115  How long will a royalty suspension volume for an 
eligible lease be effective?

    A royalty suspension volume for an eligible lease will continue 
through the end of the month in which cumulative production from the 
leases in a field entitled to share the royalty suspension volume 
reaches that volume or the lease period ends.

Sec.  560.116  How do I measure natural gas production on my eligible 
lease?

    You must measure natural gas production on your eligible lease 
subject to the royalty suspension volume as follows: 5.62 thousand 
cubic feet of natural gas, measured according to 30 CFR part 250, 
subpart L, equals one barrel of oil equivalent.

Royalty Suspension (RS) Leases

Sec.  560.120  How does royalty suspension apply to leases issued in a 
sale held after November 2000?

    We may issue leases with suspension of royalties for a period, 
volume or value of production, as authorized in section 303 of the Act. 
For purposes of this section and Sec. Sec.  560.121 through 560.124:
    (a) Any volumes of production that are not normally royalty-bearing 
under the lease or the regulations (e.g., fuel gas) do not count 
against royalty suspension volumes; and
    (b) Production includes volumes allocated to a lease under an 
approved unit agreement.

Sec.  560.121  When does a lease issued in a sale held after November 
2000 get a royalty suspension?

    (a) We will specify any royalty suspension for your RS lease in the 
Notice of OCS Lease Sale published in the Federal Register for the sale 
in which you acquire the RS lease and will repeat it in the lease 
document. In addition:
    (1) Your RS lease may produce royalty-free the royalty suspension 
we specify for your lease, even if the field to which we assign it is 
producing.
    (2) The royalty suspension we specify in the Notice of OCS Lease 
Sale for your lease does not apply to any other leases in the field to 
which we assign your RS lease.
    (b) You may apply for a supplemental royalty suspension for a 
project under 30 CFR part 203, if your lease is located:
    (1) In the Gulf of Mexico, in water 200 meters or deeper, and 
wholly west of 87 degrees, 30 minutes West longitude; or
    (2) Offshore of Alaska.
    (c) Your RS lease retains the royalty suspension with which we 
issued it even if we deny your application for more relief.

Sec.  560.122  How long will a royalty suspension volume be effective 
for a lease issued in a sale held after November 2000?

    (a) The royalty suspension volume for your RS lease will continue 
through the end of the month in which cumulative production from your 
lease reaches the applicable royalty suspension volume or the lease 
period ends.
    (b)(1) Notwithstanding any royalty suspension volume under this 
subpart, you must pay royalty at the lease stipulated rate on:
    (i) Any oil produced for any period stipulated in the lease during 
which the arithmetic average of the daily closing price on the New York 
Mercantile Exchange (NYMEX) for light sweet crude oil exceeds the 
applicable threshold price of $36.39 per barrel, adjusted annually 
after calendar year 2007 for inflation unless the lease terms prescribe 
a different price threshold.
    (ii) Any natural gas produced for any period stipulated in the 
lease during which the arithmetic average of the daily closing price on 
the NYMEX for natural gas exceeds the applicable threshold price of 
$4.55 per MMBtu, adjusted annually after calendar year 2007 for 
inflation unless the lease terms prescribe a different price threshold.
    (iii) Determine the threshold price for any calendar year after 
2007 by adjusting the threshold price in the previous year by the 
percentage that the implicit price deflator for the gross domestic 
product, as published by the Department of Commerce, changed during the 
calendar year.
    (2) You must pay any royalty due under this paragraph, plus late 
payment interest under 30 CFR 1218.54, no later than 90 days after the 
end of the period for which royalty is owed.
    (3) Any production on which you must pay royalty under this 
paragraph will count toward the production volume determined under 
Sec. Sec.  560.120 through 560.124.
    (c) If you must pay royalty on any product (either oil or natural 
gas) for any period under paragraph (b) of this section, you must 
continue to pay royalty on that product during the next succeeding 
period of the same length until the arithmetic average of the daily 
closing NYMEX prices for that product for that period can be 
determined. If the arithmetic average of the daily closing prices for 
that product for that period is less than the threshold price 
stipulated in the lease, you are entitled to a credit or refund of 
royalties paid for that period with interest under applicable law.

Sec.  560.123  How do I measure natural gas production for a lease 
issued in a sale held after November 2000?

    You must measure natural gas production subject to the royalty 
suspension volume for your lease as follows: 5.62 thousand cubic feet 
of natural gas, measured according to 30 CFR part 250, subpart L, 
equals one barrel of oil equivalent.

Sec.  560.124  How will royalty suspension apply if BOEM assigns a 
lease issued in a sale held after November 2000 to a field that has a 
pre-Act lease?

    (a) We will assign your lease that has a qualifying well (under 30 
CFR part 250, subpart A) to an existing field or

[[Page 64703]]

designate a new field and will notify you and other affected lessees 
and operating rights holders in the field of that assignment.
    (1) Within 15 days of the final notification, you or any of the 
other affected lessees or operating rights holders may file a written 
request with the Director for reconsideration, accompanied by a 
Statement of Reasons.
    (2) The Director will respond in writing either affirming or 
reversing the assignment decision. The Director's decision is the final 
action of the Department of the Interior and is not subject to appeal 
to the Interior Board of Land Appeals under 30 CFR part 590 and 43 CFR 
part 4.
    (b) If we establish a royalty suspension volume for a field as a 
result of an approved application for royalty relief submitted for a 
pre-Act lease under 30 CFR part 203, then:
    (1) Royalty-free production from your RS lease shares from and 
counts as part of any royalty suspension volume under Sec.  560.114(d) 
for the field to which we assign your lease; and
    (2) Your RS lease may continue to produce royalty-free up to the 
royalty suspension we specified for your lease, even if the field to 
which we assign your RS lease has produced all of its royalty 
suspension volume.
    (c) Your lease may share in a suspension volume larger than the 
royalty suspension with which we issued it and to the extent we grant a 
larger volume in response to an application by a pre-Act lease 
submitted under 30 CFR part 203. To share in any larger royalty 
suspension volume, you must file an application described in 30 CFR 
part 203 (Sec. Sec.  203.71 and 203.83). In no case will royalty-free 
production for your RS lease be less than the royalty suspension 
specified for your lease.

Bidding System Selection Criteria

Sec.  560.130  What criteria does BOEM use for selecting bidding 
systems and bidding system components?

    In analyzing the application of one of the bidding systems listed 
in Sec.  560.110 to tracts selected for any OCS lease sale, we may, at 
our discretion, consider the following purposes and policies. We 
recognize that each of the purposes and policies may not be 
specifically applicable to the selection process for a particular 
bidding system or tract, or may present a conflict that we will have to 
resolve in the process of bidding system selection. The order of 
listing does not denote a ranking.
    (a) Providing fair return to the Federal Government;
    (b) Increasing competition;
    (c) Ensuring competent and safe operations;
    (d) Avoiding undue speculation;
    (e) Avoiding unnecessary delays in exploration, development, and 
production;
    (f) Discovering and recovering oil and gas;
    (g) Developing new oil and gas resources in an efficient and timely 
manner;
    (h) Limiting the administrative burdens on Government and industry; 
and
    (i) Providing an opportunity to experiment with various bidding 
systems to enable us to identify those most appropriate for the 
satisfaction of the objectives of the United States in OCS lease sales.

Subpart C--[Reserved]

Subpart D--Joint Bidding

Sec.  560.301  What is the purpose of this subpart?

    The purpose of this subpart is to encourage participation in OCS 
oil and gas lease sales by limiting the requirement for filing 
``Statements of Production'' to certain joint bidders.

Sec.  560.302  What definitions apply to this subpart?

    For the purposes of this subpart, all terms used are defined as in 
30 CFR 556.40.

Sec.  560.303  What are the joint bidding requirements?

    (a) You must file a Statement of Production with the Director, 
according to the requirements of Sec. Sec.  556.38 through 556.44 if:
    (1) You submit a joint bid for any OCS oil and gas lease during a 
6-month bidding period; and
    (2) You were chargeable for the prior production period with an 
average daily production from all sources in excess of 1.6 million 
barrels of crude oil, natural gas equivalents, and liquefied petroleum 
products.
    (b) The Statement of Production that you file under paragraph (a) 
of this section must state that you are chargeable for the prior 
production period with an average daily production in excess of the 
quantities listed in paragraph (a) of this section.
    (c) If your average daily production in the prior production period 
met or exceeded the quantities specified in paragraph (a) of this 
section, you may not submit a joint bid for any OCS oil and gas lease 
during the applicable 6-month bidding period with any other person 
similarly chargeable. We will disqualify and reject these bids.
    (d) If your average daily production in the prior production period 
met or exceeded the quantities specified in paragraph (a) of this 
section, you may not enter into an agreement prior to a lease sale that 
would result in two or more persons, similarly chargeable, acquiring or 
holding any interest in the tract for which the bid is submitted. We 
will disqualify and reject these bids.

PART 570--NONDISCRIMINATION IN THE OUTER CONTINENTAL SHELF

Sec.
570.1 Purpose.
570.2 Application of this part.
570.3 Definitions.
570.4 Discrimination prohibited.
570.5 Complaint.
570.6 Process.
570.7 Remedies.

    Authority: 43 U.S.C. 1863.

Sec.  570.1  Purpose.

    The purpose of this part is to implement the provisions of section 
604 of the OCSLA of 1978 which provides that ``no person shall, on the 
grounds of race, creed, color, national origin, or sex, be excluded 
from receiving or participating in any activity, sale, or employment, 
conducted pursuant to the provisions of * * * the Outer Continental 
Shelf Lands Act.''

Sec.  570.2  Application of this part.

    This part applies to any contract or subcontract entered into by a 
lessee or by a contractor or subcontractor of a lessee after the 
effective date of these regulations to provide goods, services, 
facilities, or property in an amount of $10,000 or more in connection 
with any activity related to the exploration for or development and 
production of oil, gas, or other minerals or materials in the OCS under 
the Act.

Sec.  570.3  Definitions.

    As used in this part, the following terms shall have the following 
meaning:
    Contract means any business agreement or arrangement (in which the 
parties do not stand in the relationship of employer and employee) 
between a lessee and any person which creates an obligation to provide 
goods, services, facilities, or property.
    Lessee means the party authorized by a lease, grant of right-of-
way, or an approved assignment thereof to explore, develop, produce, or 
transport oil, gas, or other minerals or materials in the OCS pursuant 
to the Act and this part.
    Person means a person or company, including but not limited to, a 
corporation, partnership, association, joint stock venture, trust, 
mutual fund, or any receiver, trustee in bankruptcy,

[[Page 64704]]

or other official acting in a similar capacity for such company.
    Subcontract means any business agreement or arrangement (in which 
the parties do not stand in the relationship of employer and employee) 
between a lessee's contractor and any person other than a lessee that 
is in any way related to the performance of any one or more contracts.

Sec.  570.4  Discrimination prohibited.

    No contract or subcontract to which this part applies shall be 
denied to or withheld from any person on the grounds of race, creed, 
color, national origin, or sex.

Sec.  570.5  Complaint.

    (a) Whenever any person believes that he or she has been denied a 
contract or subcontract to which this part applies on the grounds of 
race, creed, color, national origin, or sex, such person may complain 
of such denial or withholding to the Regional Director of the OCS 
Region in which such action is alleged to have occurred. Any complaint 
filed under this part must be submitted in writing to the appropriate 
Regional Director not later than 180 days after the date of the alleged 
unlawful denial of a contract or subcontract which is the basis of the 
complaint.
    (b) The complaint referred to in paragraph (a) of this section 
shall be accompanied by such evidence as may be available to a person 
and which is relevant to the complaint including affidavits and other 
documents.
    (c) Whenever any person files a complaint under this part, the 
Regional Director with whom such complaint is filed shall give written 
notice of such filing to all persons cited in the complaint no later 
than 10 days after receipt of such complaint. Such notice shall include 
a statement describing the alleged incident of discrimination, 
including the date and the names of persons involved in it.

Sec.  570.6  Process.

    Whenever a Regional Director determines on the basis of any 
information, including that which may be obtained under Sec.  570.5 of 
this part, that a violation of or failure to comply with any provision 
of this subpart probably occurred, the Regional Director shall 
undertake to afford the complainant and the person(s) alleged to have 
violated the provisions of this part an opportunity to engage in 
informal consultations, meetings, or any other form of communications 
for the purpose of resolving the complaint. In the event such 
communications or consultations result in a mutually satisfactory 
resolution of the complaint, the complainant and all persons cited in 
the complaint shall notify the Regional Director in writing of their 
agreement to such resolution. If either the complainant or the 
person(s) alleged to have wrongfully discriminated fail to provide such 
written notice within a reasonable period of time, the Regional 
Director must proceed in accordance with the provisions of 30 CFR part 
550, subpart N.

Sec.  570.7  Remedies.

    In addition to the penalties available under 30 CFR part 550, 
subpart N, the Director may invoke any other remedies available to him 
or her under the Act or regulations for the lessee's failure to comply 
with provisions of the Act, regulations, or lease.

PART 580--PROSPECTING FOR MINERALS OTHER THAN OIL, GAS, AND SULPHUR 
ON THE OUTER CONTINENTAL SHELF

Subpart A--General Information
Sec. 580.1 What definitions apply to this part?
580.2 What is the purpose of this part?
580.3 What requirements must I follow when I conduct prospecting or 
research activities?
580.4 What activities are not covered by this part?
Subpart B--How To Apply for a Permit or File a Notice
580.10 What must I do before I may conduct prospecting activities?
580.11 What must I do before I may conduct scientific research?
580.12 What must I include in my application or notification?
580.13 Where must I send my application or notification?
Subpart C--Obligations Under This Part

Prohibitions and Requirements

580.20 What must I not do in conducting Geological and Geophysical 
(G&G) prospecting or scientific research?
580.21 What must I do in conducting G&G prospecting or scientific 
research?
580.22 What must I do when seeking approval for modifications?
580.23 How must I cooperate with inspection activities?
580.24 What reports must I file?

Interrupted Activities

580.25 When may BOEM require me to stop activities under this part?
580.26 When may I resume activities?
580.27 When may BOEM cancel my permit?
580.28 May I relinquish my permit?

Environmental Issues

580.29 Will BOEM monitor the environmental effects of my activity?
580.30 What activities will not require environmental analysis?
580.31 Whom will BOEM notify about environmental issues?

Penalties and Appeals

580.32 What penalties may I be subject to?
580.33 How can I appeal a penalty?
580.34 How can I appeal an order or decision?
Subpart D--Data Requirements

Geological Data and Information

580.40 When do I notify BOEM that geological data and information 
are available for submission, inspection, and selection?
580.41 What types of geological data and information must I submit 
to BOEM?
580.42 When geological data and information are obtained by a third 
party, what must we both do?

Geophysical Data and Information

580.50 When do I notify BOEM that geophysical data and information 
are available for submission, inspection, and selection?
580.51 What types of geophysical data and information must I submit 
to BOEM?
580.52 When geophysical data and information are obtained by a third 
party, what must we both do?

Reimbursement

580.60 Which of my costs will be reimbursed?
580.61 Which of my costs will not be reimbursed?

Protections

580.70 What data and information will be protected from public 
disclosure?
580.71 What is the timetable for release of data and information?
580.72 What procedure will BOEM follow to disclose acquired data and 
information to a contractor for reproduction, processing, and 
interpretation?
580.73 Will BOEM share data and information with coastal States?
Subpart E--Information Collection
580.80 Paperwork Reduction Act statement--information collection.

    Authority: 31 U.S.C. 9701, 43 U.S.C. 1334.

Subpart A--General Information

Sec.  580.1  What definitions apply to this part?

    Definitions in this part have the following meaning:
    Act means the OCS Lands Act, as amended (43 U.S.C. 1331 et seq.).
    Adjacent State means with respect to any activity proposed, 
conducted, or approved under this part, any coastal State(s):
    (1) That is used, or is scheduled to be used, as a support base for 
geological and geophysical (G&G) prospecting or scientific research 
activities; or
    (2) In which there is a reasonable probability of significant 
effect on land or water uses from such activity.

[[Page 64705]]

    Analyzed geological information means data collected under a permit 
or a lease that have been analyzed. Some examples of analysis include, 
but are not limited to, identification of lithologic and fossil 
content, core analyses, laboratory analyses of physical and chemical 
properties, well logs or charts, results from formation fluid tests, 
and descriptions of mineral occurrences or hazardous conditions.
    Archaeological interest means capable of providing scientific or 
humanistic understandings of past human behavior, cultural adaptation, 
and related topics through the application of scientific or scholarly 
techniques, such as controlled observation, contextual measurement, 
controlled collection, analysis, interpretation, and explanation.
    Archaeological resource means any material remains of human life or 
activities that are at least 50 years of age and are of archaeological 
interest.
    Coastal environment means the physical, atmospheric, and biological 
components, conditions, and factors that interactively determine the 
productivity, state, condition, and quality of the terrestrial 
ecosystem from the shoreline inward to the boundaries of the coastal 
zone.
    Coastal zone means the coastal waters (including the lands therein 
and thereunder) and the adjacent shorelands (including the waters 
therein and thereunder) that are strongly influenced by each other and 
in proximity to the shorelands of the several coastal States. The 
coastal zone includes islands, transition and intertidal areas, salt 
marshes, wetlands, and beaches. The coastal zone extends seaward to the 
outer limit of the United States territorial sea and extends inland 
from the shorelines to the extent necessary to control shorelands, the 
uses of which have a direct and significant impact on the coastal 
waters, and the inward boundaries of which may be identified by the 
several coastal States, under the authority in section 305(b)(1) of the 
Coastal Zone Management Act of 1972.
    Coastal Zone Management Act means the Coastal Zone Management Act 
of 1972, as amended (16 U.S.C. 1451 et seq.).
    Data means facts and statistics, measurements, or samples that have 
not been analyzed, processed, or interpreted.
    Deep stratigraphic test means drilling that involves the 
penetration into the sea bottom of more than 500 feet (152 meters).
    Director means the Director of the Bureau of Ocean Energy 
Management, U.S. Department of the Interior, or an official authorized 
to act on the Director's behalf.
    Geological and geophysical (G&G) prospecting activities mean the 
commercial search for mineral resources other than oil, gas, or 
sulphur. Activities classified as prospecting include, but are not 
limited to:
    (1) Geological and geophysical marine and airborne surveys where 
magnetic, gravity, seismic reflection, seismic refraction, or the 
gathering through coring or other geological samples are used to detect 
or imply the presence of hard minerals; and
    (2) Any drilling, whether on or off a geological structure.
    Geological and geophysical (G&G) scientific research activities 
mean any investigations related to hard minerals that are conducted on 
the OCS for academic or scientific research. These investigations would 
involve gathering and analyzing geological, geochemical, or geophysical 
data and information that are made available to the public for 
inspection and reproduction at the earliest practical time. The term 
does not include commercial G&G exploration or commercial G&G 
prospecting activities.
    Geological data and information means data and information gathered 
through or derived from geological and geochemical techniques, e.g., 
coring and test drilling, well logging, bottom sampling, or other 
physical sampling or chemical testing process.
    Geological sample means a collected portion of the seabed, the 
subseabed, or the overlying waters acquired while conducting 
prospecting or scientific research activities.
    Geophysical data and information means any data or information 
gathered through or derived from geophysical measurement or sensing 
techniques (e.g., gravity, magnetic, or seismic).
    Governor means the Governor of a State or the person or entity 
lawfully designated by or under State law to exercise the powers 
granted to a Governor under the Act.
    Hard minerals mean any minerals found on or below the surface of 
the seabed except for oil, gas, or sulphur.
    Interpreted geological information means the knowledge, often in 
the form of schematic cross sections, 3-dimensional representations, 
and maps, developed by determining the geological significance of 
geological data and analyzed and processed geologic information.
    Interpreted geophysical information means knowledge, often in the 
form of seismic cross sections, 3-dimensional representations, and 
maps, developed by determining the geological significance of 
geophysical data and processed geophysical information.
    Lease means, depending upon the requirements of the context, 
either:
    (1) An agreement issued under section 8 or maintained under section 
6 of the Act that authorizes mineral exploration, development and 
production; or
    (2) The area covered by an agreement specified in paragraph (1) of 
this definition.
    Material remains means physical evidence of human habitation, 
occupation, use, or activity, including the site, location, or context 
in which evidence is situated.
    Minerals mean all minerals authorized by an Act of Congress to be 
produced from ``public lands'' as defined in section 103 of the Federal 
Land Policy and Management Act of 1976 (43 U.S.C. 1702). The term 
includes oil, gas, sulphur, geopressured-geothermal and associated 
resources.
    Notice means a written statement of intent to conduct G&G 
scientific research that is:
    (1) Related to hard minerals on the OCS; and
    (2) Not covered under a permit.
    Oil, gas, and sulphur means oil, gas, and sulphur, geopressured-
geothermal and associated resources, including gas hydrates.
    Outer Continental Shelf (OCS) means all submerged lands:
    (1) That lie seaward and outside of the area of lands beneath 
navigable waters as defined in section 2 of the Submerged Lands Act (43 
U.S.C. 1301); and
    (2) Whose subsoil and seabed belong to the United States and are 
subject to its jurisdiction and control.
    Permit means the contract or agreement, other than a lease, issued 
under this part. The permit gives a person the right, under appropriate 
statutes, regulations, and stipulations, to conduct on the OCS:
    (1) Geological prospecting for hard minerals;
    (2) Geophysical prospecting for hard minerals;
    (3) Geological scientific research; or
    (4) Geophysical scientific research.
    Permittee means the person authorized by a permit issued under this 
part to conduct activities on the OCS.
    Person means:
    (1) A citizen or national of the United States;
    (2) An alien lawfully admitted for permanent residence in the 
United States as defined in section 8 U.S.C. 1101(a)(20);
    (3) A private, public, or municipal corporation organized under the 
laws of the United States or of any State or territory thereof, and 
association of such

[[Page 64706]]

citizens, nationals, resident aliens or private, public, or municipal 
corporations, States, or political subdivisions of States; or
    (4) Anyone operating in a manner provided for by treaty or other 
applicable international agreements. The term does not include Federal 
agencies.
    Processed geological or geophysical information means data 
collected under a permit and later processed or reprocessed.
    (1) Processing involves changing the form of data as to facilitate 
interpretation. Some examples of processing operations may include, but 
are not limited to:
    (i) Applying corrections for known perturbing causes;
    (ii) Rearranging or filtering data; and
    (iii) Combining or transforming data elements.
    (2) Reprocessing is the additional processing other than ordinary 
processing used in the general course of evaluation. Reprocessing 
operations may include varying identified parameters for the detailed 
study of a specific problem area.
    Secretary means the Secretary of the Interior or a subordinate 
authorized to act on the Secretary's behalf.
    Shallow test drilling means drilling into the sea bottom to depths 
less than those specified in the definition of a deep stratigraphic 
test.
    Significant archaeological resource means those archaeological 
resources that meet the criteria of significance for eligibility of the 
National Register of Historic Places as defined in 36 CFR 60.4, or its 
successor.
    Third party means any person other than the permittee or a 
representative of the United States, including all persons who obtain 
data or information acquired under a permit from the permittee, or from 
another third party, by sale, trade, license agreement, or other means.
    You means a person who applies for and/or obtains a permit, or 
files a notice to conduct G&G prospecting or scientific research 
related to hard minerals on the OCS.

Sec.  580.2  What is the purpose of this part?

    The purpose of this part is to:
    (a) Allow you to conduct prospecting activities or scientific 
research activities on the OCS in Federal waters related to hard 
minerals on unleased lands or on lands under lease to a third party.
    (b) Ensure that you carry out prospecting activities or scientific 
research activities in a safe and environmentally sound manner so as to 
prevent harm or damage to, or waste of, any natural resources 
(including any hard minerals in areas leased or not leased), any life 
(including fish and other aquatic life), property, or the marine, 
coastal, or human environment.
    (c) Inform you and third parties of your legal and contractual 
obligations.
    (d) Inform you and third parties of:
    (1) The U.S. Government's rights to access G&G data and information 
collected under permit on the OCS;
    (2) Reimbursement we will make for data and information that are 
submitted; and
    (3) The proprietary terms of data and information that we retain.

Sec.  580.3  What requirements must I follow when I conduct prospecting 
or research activities?

    You must conduct G&G prospecting activities or scientific research 
activities under this part according to:
    (a) The Act;
    (b) The regulations in this part;
    (c) Orders of the Director/Regional Director (RD); and
    (d) Other applicable statutes, regulations, and amendments.

Sec.  580.4  What activities are not covered by this part?

    This part does not apply to:
    (a) G&G prospecting activities conducted by, or on behalf of, the 
lessee on a lease on the OCS;
    (b) Federal agencies;
    (c) Postlease activities for mineral resources other than oil, gas, 
and sulphur, which are covered by regulations at 30 CFR parts 582 and 
282; and
    (d) G&G exploration or G&G scientific research activities related 
to oil, gas, and sulphur, including gas hydrates, which are covered by 
regulations at 30 CFR parts 551 and 251.

Subpart B--How To Apply for a Permit or File a Notice

Sec.  580.10  What must I do before I may conduct prospecting 
activities?

    You must have a BOEM-approved permit to conduct G&G prospecting 
activities, including deep stratigraphic tests, for hard minerals. If 
you conduct both G&G prospecting activities, you must have a separate 
permit for each.

Sec.  580.11  What must I do before I may conduct scientific research?

    You may conduct G&G scientific research activities related to hard 
minerals on the OCS only after you obtain a BOEM-approved permit or 
file a notice.
    (a) Permit. You must obtain a permit if the research activities you 
want to conduct involve:
    (1) Using solid or liquid explosives;
    (2) Drilling a deep stratigraphic test; or
    (3) Developing data and information for proprietary use or sale.
    (b) Notice. If you conduct research activities (including federally 
funded research) not covered by paragraph (a) of this section, you must 
file a notice with the regional director at least 30 days before you 
begin. If you cannot file a 30-day notice, you must provide oral 
notification before you begin and follow up in writing. You must also 
inform BOEM in writing when you conclude your work.

Sec.  580.12  What must I include in my application or notification?

    (a) Permits. You must submit to the Regional Director a signed 
original and three copies of the permit application form (Form BOEM-
0134) at least 30 days before the startup date for activities in the 
permit area. If unusual circumstances prevent you from meeting this 
deadline, you must immediately contact the Regional Director to arrange 
an acceptable deadline. The form includes names of persons; the type, 
location, purpose, and dates of activity; and environmental and other 
information. A nonrefundable service fee of $2,012 must be paid 
electronically through Pay.gov at: https://www.pay.gov/paygov/ and you 
must include a copy of the Pay.gov confirmation receipt page with your 
application.
    (b) Disapproval of permit application. If we disapprove your 
application for a permit, the RD will explain the reasons for the 
disapproval and what you must do to obtain approval.
    (c) Notices. You must sign and date a notice that includes:
    (1) The name(s) of the person(s) who will conduct the proposed 
research;
    (2) The name(s) of any other person(s) participating in the 
proposed research, including the sponsor;
    (3) The type of research and a brief description of how you will 
conduct it;
    (4) A map, plat, or chart, that shows the location where you will 
conduct research;
    (5) The proposed projected starting and ending dates for your 
research activity;
    (6) The name, registry number, registered owner, and port of 
registry of vessels used in the operation;
    (7) The earliest practical time you expect to make the data and 
information resulting from your research activity available to the 
public;
    (8) Your plan of how you will make the data and information you 
collect available to the public;
    (9) A statement that you and others involved will not sell or 
withhold the

[[Page 64707]]

data and information resulting from your research; and
    (10) At your option, the nonexclusive use agreement for scientific 
research attachment to Form BOEM-0134. (If you submit this agreement, 
you do not have to submit the material required in paragraphs (c)(7), 
(c)(8), and (c)(9) of this section.)

Sec.  580.13  Where must I send my application or notification?

    You must apply for a permit or file a notice at one of the 
following locations:

 
------------------------------------------------------------------------
  For the OCS off the . . .                  Apply to . . .
------------------------------------------------------------------------
(a) State of Alaska..........  Regional Supervisor for Resource
                                Evaluation, Bureau of Ocean Energy
                                Management, Alaska OCS Region, 3801
                                Centerpoint Drive, Suite 500, Anchorage,
                                AK 99503.
(b) Atlantic Coast, Gulf of    Regional Supervisor for Resource
 Mexico, Puerto Rico, or U.S.   Evaluation, Bureau of Ocean Energy
 territories in the Caribbean   Management, Gulf of Mexico OCS Region,
 Sea.                           1201 Elmwood Park Boulevard, New
                                Orleans, LA 70123.
(c) States of California,      Regional Supervisor for Resource
 Oregon, Washington, Hawaii,    Evaluation, Bureau of Ocean Energy
 or U.S. territories in the     Management, Pacific OCS Region, 770
 Pacific Ocean.                 Paseo Camarillo, Camarillo, CA 93010.
------------------------------------------------------------------------

Subpart C--Obligations Under This Part

Prohibitions and Requirements

Sec.  580.20  What must I not do in conducting Geological and 
Geophysical (G&G) prospecting or scientific research?

    While conducting G&G prospecting or scientific research activities 
under a permit or notice, you must not:
    (a) Interfere with or endanger operations under any lease, right-
of-way, easement, right-of-use, notice, or permit issued or maintained 
under the Act;
    (b) Cause harm or damage to life (including fish and other aquatic 
life), property, or the marine, coastal, or human environment;
    (c) Cause harm or damage to any mineral resources (in areas leased 
or not leased);
    (d) Cause pollution;
    (e) Disturb archaeological resources;
    (f) Create hazardous or unsafe conditions;
    (g) Unreasonably interfere with or cause harm to other uses of the 
area; or
    (h) Claim any oil, gas, sulphur, or other minerals you discover 
while conducting operations under a permit or notice.

Sec.  580.21  What must I do in conducting G&G prospecting or 
scientific research?

    While conducting G&G prospecting or scientific research activities 
under a permit or notice, you must:
    (a) Immediately report to the Regional Director if you:
    (1) Detect hydrocarbon or any other mineral occurrences;
    (2) Detect environmental hazards that imminently threaten life and 
property; or
    (3) Adversely affect the environment, aquatic life, archaeological 
resources, or other uses of the area where you are prospecting or 
conducting scientific research activities.
    (b) Consult and coordinate your G&G activities with other users of 
the area for navigation and safety purposes.
    (c) If you conduct shallow test drilling or deep stratigraphic test 
drilling activities, you must use the best available and safest 
technologies that the Regional Director considers economically 
feasible.

Sec.  580.22  What must I do when seeking approval for modifications?

    Before you begin modified operations, you must submit a written 
request describing the modifications and receive the Regional 
Director's oral or written approval. If circumstances preclude a 
written request, you must make an oral request and follow up in 
writing.

Sec.  580.23  How must I cooperate with inspection activities?

    (a) You must allow our representatives to inspect your G&G 
prospecting or any scientific research activities that are being 
conducted under a permit. They will determine whether operations are 
adversely affecting the environment, aquatic life, archaeological 
resources, or other uses of the area.
    (b) BOEM will reimburse you for food, quarters, and transportation 
that you provide for our representatives if you send in your 
reimbursement request to the region that issued the permit within 90 
days of the inspection.

Sec.  580.24  What reports must I file?

    (a) You must submit status reports on a schedule specified in the 
permit and include a daily log of operations.
    (b) You must submit a final report of G&G prospecting or scientific 
research activities under a permit within 30 days after you complete 
acquisition activities under the permit. You may combine the final 
report with the last status report and must include each of the 
following:
    (1) A description of the work performed.
    (2) Charts, maps, plats and digital navigation data in a format 
specified by the Regional Director, showing the areas and blocks in 
which any G&G prospecting or permitted scientific research activities 
were conducted. Identify the lines of geophysical traverses and their 
locations including a reference sufficient to identify the data 
produced during each activity.
    (3) The dates on which you conducted the actual prospecting or 
scientific research activities.
    (4) A summary of any:
    (i) Hard mineral, hydrocarbon, or sulphur occurrences encountered;
    (ii) Environmental hazards; and
    (iii) Adverse effects of the G&G prospecting or scientific research 
activities on the environment, aquatic life, archaeological resources, 
or other uses of the area in which the activities were conducted.
    (5) Other descriptions of the activities conducted as specified by 
the Regional Director.

Interrupted Activities

Sec.  580.25  When may BOEM require me to stop activities under this 
part?

    (a) We may temporarily stop prospecting or scientific research 
activities under a permit when the Regional Director determines that:
    (1) Activities pose a threat of serious, irreparable, or immediate 
harm. This includes damage to life (including fish and other aquatic 
life), property, and any minerals (in areas leased or not leased), to 
the marine, coastal, or human environment, or to an archaeological 
resource;
    (2) You failed to comply with any applicable law, regulation, order 
or provision of the permit. This would include our required submission 
of reports, well records or logs, and G&G data and information within 
the time specified; or
    (3) Stopping the activities is in the interest of National security 
or defense.

[[Page 64708]]

    (b) The Regional Director will advise you either orally or in 
writing of the procedures to temporarily stop activities. We will 
confirm an oral notification in writing and deliver all written 
notifications by courier or certified/registered mail. You must stop 
all activities under a permit as soon as you receive an oral or written 
notification.

Sec.  580.26  When may I resume activities?

    The Regional Director will advise you when you may start your 
permit activities again.

Sec.  580.27  When may BOEM cancel my permit?

    The Regional Director may cancel a permit at any time.
    (a) If we cancel your permit, the Regional Director will advise you 
by certified or registered mail 30 days before the cancellation date 
and will state the reason.
    (b) After we cancel your permit, you are still responsible for 
proper abandonment of any drill site according to the requirements of 
30 CFR 251.7(b)(8). You must comply with all other obligations 
specified in this part or in the permit.

Sec.  580.28  May I relinquish my permit?

    (a) You may relinquish your permit at any time by advising the 
Regional Director by certified or registered mail 30 days in advance.
    (b) After you relinquish your permit, you are still responsible for 
proper abandonment of any drill sites according to the requirements of 
30 CFR 251.7(b)(8). You must also comply with all other obligations 
specified in this part or in the permit.

Environmental Issues

Sec.  580.29  Will BOEM monitor the environmental effects of my 
activity?

    We will evaluate the potential of proposed prospecting or 
scientific research activities for adverse impact on the environment to 
determine the need for mitigation measures.

Sec.  580.30  What activities will not require environmental analysis?

    We anticipate that activities of the type listed below typically 
will not cause significant environmental impact and will normally be 
categorically excluded from additional environmental analysis. The 
types of activities include:
    (a) Gravity and magnetometric observations and measurements;
    (b) Bottom and subbottom acoustic profiling or imaging without the 
use of explosives;
    (c) Hard minerals sampling of a limited nature such as shallow test 
drilling;
    (d) Water and biotic sampling, if the sampling does not adversely 
affect shellfish beds, marine mammals, or an endangered species or if 
permitted by the National Marine Fisheries Service or another Federal 
agency;
    (e) Meteorological observations and measurements, including the 
setting of instruments;
    (f) Hydrographic and oceanographic observations and measurements, 
including the setting of instruments;
    (g) Sampling by box core or grab sampler to determine seabed 
geological or geotechnical properties;
    (h) Television and still photographic observation and measurements;
    (i) Shipboard hard mineral assaying and analysis; and
    (j) Placement of positioning systems, including bottom transponders 
and surface and subsurface buoys reported in Notices to Mariners.

Sec.  580.31  Whom will BOEM notify about environmental issues?

    (a) In cases where Coastal Zone Management Act consistency review 
is required, the Director will notify the Governor of each adjacent 
State with a copy of the application for a permit immediately upon the 
submission for approval.
    (b) In cases where an environmental assessment is to be prepared, 
the Director will invite the Governor of each adjacent State to review 
and provide comments regarding the proposed activities. The Director's 
invitation to provide comments will allow the Governor a specified 
period of time to comment.
    (c) When a permit is issued, the Director will notify affected 
parties including each affected coastal State, Federal agency, local 
government, and special interest organization that has expressed an 
interest.

Penalties and Appeals

Sec.  580.32  What penalties may I be subject to?

    (a) Penalties for noncompliance under a permit. You are subject to 
the penalty provisions of section 24 of the Act (43 U.S.C. 1350) and 
the procedures contained in 30 CFR part 550, subpart N for 
noncompliance with:
    (1) Any provision of the Act;
    (2) Any provisions of a G&G or drilling permit; or
    (3) Any regulation or order issued under the Act.
    (b) Penalties under other laws and regulations. The penalties 
prescribed in this section are in addition to any other penalty imposed 
by any other law or regulation.

Sec.  580.33  How can I appeal a penalty?

    See 30 CFR part 550.1409 and 30 CFR part 590, subpart A, for 
instructions on how to appeal any decision assessing a civil penalty 
under 43 U.S.C. 1350 and 30 CFR part 550, subpart A.

Sec.  580.34  How can I appeal an order or decision?

    See 30 CFR part 590, subpart A, for instructions on how to appeal 
an order or decision.

Subpart D--Data Requirements

Geological Data and Information

Sec.  580.40  When do I notify BOEM that geological data and 
information are available for submission, inspection, and selection?

    (a) You must notify the Regional Director, in writing, when you 
complete the initial analysis, processing, or interpretation of any 
geological data and information. Initial analysis and processing are 
the stages of analysis or processing where the data and information 
first become available for in-house interpretation by the permittee or 
become available commercially to third parties via sale, trade, license 
agreement, or other means.
    (b) The Regional Director may ask if you have further analyzed, 
processed, or interpreted any geological data and information. When 
asked, you must respond to us in writing within 30 days.
    (c) The Regional Director may ask you or a third party to submit 
the analyzed, processed, or interpreted geologic data and information 
for us to inspect or permanently retain. You must submit the data and 
information within 30 days after such a request.

Sec.  580.41  What types of geological data and information must I 
submit to BOEM?

    Unless the Regional Director specifies otherwise, you must submit 
geological data and information that include:
    (a) An accurate and complete record of all geological (including 
geochemical) data and information describing each operation of 
analysis, processing, and interpretation;
    (b) Paleontological reports identifying by depth any microscopic 
fossils collected, including the reference datum to which 
paleontological sample depths are related and, if the Regional Director 
requests, washed samples, that you maintain for paleontological 
determinations;
    (c) Copies of well logs or charts in a digital format, if 
available;
    (d) Results and data obtained from formation fluid tests;

[[Page 64709]]

    (e) Analyses of core or bottom samples and/or a representative cut 
or split of the core or bottom sample;
    (f) Detailed descriptions of any hydrocarbons or other minerals or 
hazardous conditions encountered during operations, including near 
losses of well control, abnormal geopressures, and losses of 
circulation; and
    (g) Other geological data and information that the RD may specify.

Sec.  580.42  When geological data and information are obtained by a 
third party, what must we both do?

    A third party may obtain geological data and information from a 
permittee, or from another third party, by sale, trade, license 
agreement, or other means. If this happens:
    (a) The third-party recipient of the data and information assumes 
the obligations under this part, except for the notification provisions 
of Sec.  580.40(a) and is subject to the penalty provisions of Sec.  
580.32(a)(1) and 30 CFR part 550, subpart N; and
    (b) A permittee or third party that sells, trades, licenses, or 
otherwise provides data and information to a third party must advise 
the recipient, in writing, that accepting these obligations is a 
condition precedent of the sale, trade, license, or other agreement; 
and
    (c) Except for license agreements, a permittee or third party that 
sells, trades, or otherwise provides data and information to a third 
party must advise the Regional Director in writing within 30 days of 
the sale, trade, or other agreement, including the identity of the 
recipient of the data and information; or
    (d) For license agreements, a permittee or third party that 
licenses data and information to a third party must, within 30 days of 
a request by the Regional Director, advise the Regional Director, in 
writing, of the license agreement, including the identity of the 
recipient of the data and information.

Geophysical Data and Information

Sec.  580.50  When do I notify BOEM that geophysical data and 
information are available for submission, inspection, and selection?

    (a) You must notify the Regional Director in writing when you 
complete the initial processing and interpretation of any geophysical 
data and information. Initial processing is the stage of processing 
where the data and information become available for in-house 
interpretation by the permittee, or become available commercially to 
third parties via sale, trade, license agreement, or other means.
    (b) The Regional Director may ask whether you have further 
processed or interpreted any geophysical data and information. When 
asked, you must respond to us in writing within 30 days.
    (c) The Regional Director may request that the permittee or third 
party submit geophysical data and information before making a final 
selection for retention. Our representatives may inspect and select the 
data and information on your premises, or the Regional Director can 
request delivery of the data and information to the appropriate 
regional office for review.
    (d) You must submit the geophysical data and information within 30 
days of receiving the request, unless the Regional Director extends the 
delivery time.
    (e) At any time before final selection, the Regional Director may 
review and return any or all geophysical data and information. We will 
notify you in writing of any data the RD decides to retain.

Sec.  580.51  What types of geophysical data and information must I 
submit to BOEM?

    Unless the Regional Director specifies otherwise, you must include:
    (a) An accurate and complete record of each geophysical survey 
conducted under the permit, including digital navigational data and 
final location maps;
    (b) All seismic data collected under a permit presented in a format 
and of a quality suitable for processing;
    (c) Processed geophysical information derived from seismic data 
with extraneous signals and interference removed, presented in a 
quality format suitable for interpretive evaluation, reflecting state-
of-the-art processing techniques; and
    (d) Other geophysical data, processed geophysical information, and 
interpreted geophysical information including, but not limited to, 
shallow and deep subbottom profiles, bathymetry, sidescan sonar, 
gravity and magnetic surveys, and special studies such as refraction 
and velocity surveys.

Sec.  580.52  When geophysical data and information are obtained by a 
third party, what must we both do?

    A third party may obtain geophysical data, processed geophysical 
information, or interpreted geophysical information from a permittee, 
or from another third party, by sale, trade, license agreement, or 
other means. If this happens:
    (a) The third-party recipient of the data and information assumes 
the obligations under this part, except for the notification provisions 
of Sec.  580.50(a) and is subject to the penalty provisions of Sec.  
580.32(a)(1) and 30 CFR 550, subpart N; and
    (b) A permittee or third party that sells, trades, licenses, or 
otherwise provides data and information to a third party must advise 
the recipient, in writing, that accepting these obligations is a 
condition precedent of the sale, trade, license, or other agreement; 
and
    (c) Except for license agreements, a permittee or third party that 
sells, trades, or otherwise provides data and information to a third 
party must advise the Regional Director, in writing within 30 days of 
the sale, trade, or other agreements, including the identity of the 
recipient of the data and information; or
    (d) For license agreements, a permittee or third party that 
licenses data and information to a third party must, within 30 days of 
a request by the Regional Director, advise the Regional Director, in 
writing, of the license agreement, including the identity of the 
recipient of the data and information.

Reimbursement

Sec.  580.60  Which of my costs will be reimbursed?

    (a) We will reimburse you or a third party for reasonable costs of 
reproducing data and information that the Regional Director requests 
if:
    (1) You deliver G&G data and information to us for the Regional 
Director to inspect or select and retain (according to Sec. Sec.  
580.40 and 580.50);
    (2) We receive your request for reimbursement and the Regional 
Director determines that the requested reimbursement is proper; and
    (3) The cost is at your lowest rate (or a third party's) or at the 
lowest commercial rate established in the area, whichever is less.
    (b) We will reimburse you or the third party for the reasonable 
costs of processing geophysical information (which does not include 
cost of data acquisition) if, at the request of the Regional Director, 
you processed the geophysical data or information in a form or manner 
other than that used in the normal conduct of business.

Sec.  580.61  Which of my costs will not be reimbursed?

    (a) When you request reimbursement, you must identify reproduction 
and processing costs separately from acquisition costs.
    (b) We will not reimburse you or a third party for data acquisition 
costs or for the costs of analyzing or processing geological 
information or interpreting geological or geophysical information.

[[Page 64710]]

Protections

Sec.  580.70  What data and information will be protected from public 
disclosure?

    In making data and information available to the public, the 
Regional Director will follow the applicable requirements of:
    (a) The Freedom of Information Act (5 U.S.C. 552);
    (b) The implementing regulations at 43 CFR part 2;
    (c) The Act; and
    (d) The regulations at 30 CFR parts 550 and 552.
    (1) If the RD determines that any data or information is exempt 
from disclosure under the Freedom of Information Act, we will not 
disclose the data and information unless either:
    (i) You and all third parties agree to the disclosure; or
    (ii) A provision of 30 CFR parts 550 and 552 allows us to make the 
disclosure.
    (2) We will keep confidential the identity of third-party 
recipients of data and information collected under a permit. We will 
not release the identity unless you and the third parties agree to the 
disclosure.
    (3) When you detect any significant hydrocarbon occurrences or 
environmental hazards on unleased lands during drilling operations, the 
Regional Director will immediately issue a public announcement. The 
announcement must further the National interest without unduly damaging 
your competitive position.

Sec.  580.71  What is the timetable for release of data and 
information?

    We will release data and information that you or a third party 
submits and we retain according to paragraphs (a) and (b) of this 
section.
    (a) If the data and information are not related to a deep 
stratigraphic test, we will release them to the public according to 
items (1), (2), and (3) in the following table:

------------------------------------------------------------------------
                                             The Regional Director will
  If you or a third party submits and we     disclose them to the public
               retain . . .                             . . .
------------------------------------------------------------------------
(1) Geological data and information,        10 years after issuing the
                                             permit.
(2) Geophysical data,                       50 years after you or a
                                             third party submit the
                                             data.
(3) Geophysical information,                25 years after you or a
                                             third party submit the
                                             information.
(4) Data and information related to a deep  25 years after you complete
 stratigraphic test,                         the test, unless the
                                             provisions of paragraph (b)
                                             of this section apply.
------------------------------------------------------------------------

    (b) This paragraph applies if you are covered by paragraph (a)(4) 
of this section and a lease sale is held or a noncompetitive agreement 
is negotiated after you complete a test well. We will release the data 
and information related to the deep stratigraphic test at the earlier 
of the following times:
    (1) Twenty-five years after you complete the test; or
    (2) Sixty calendar days after we issue a lease, located partly or 
totally within 50 geographic miles (92.7 kilometers) of the test.

Sec.  580.72  What procedure will BOEM follow to disclose acquired data 
and information to a contractor for reproduction, processing, and 
interpretation?

    (a) When practical, the Regional Director will advise the person 
who submitted data and information under Sec.  580.40 or Sec.  580.50 
of the intent to provide the data or information to an independent 
contractor or agent for reproduction, processing, and interpretation.
    (b) The person notified will have at least five working days to 
comment on the action.
    (c) When the Regional Director advises the person who submitted the 
data and information, all other owners of the data or information will 
be considered to have been notified.
    (d) The independent contractor or agent must sign a written 
commitment not to sell, trade, license, or disclose data or information 
to anyone without the Regional Director's consent.

Sec.  580.73  Will BOEM share data and information with coastal States?

    (a) We can disclose proprietary data, information, and samples 
submitted to us by permittees or third parties that we receive under 
this part to the Governor of any adjacent State that requests it 
according to paragraphs (b), (c), and (d) of this section. The 
permittee or third parties who submitted proprietary data, information, 
and samples will be notified about the disclosure and will have at 
least five working days to comment on the action.
    (b) We will make a disclosure under this section only after the 
Governor and the Secretary have entered into an agreement containing 
all of the following provisions:
    (1) The confidentiality of the information will be maintained.
    (2) In any action taken for failure to protect the confidentiality 
of proprietary information, neither the Federal Government nor the 
State may raise as a defense:
    (i) Any claim of sovereign immunity; or
    (ii) Any claim that the employee who revealed the proprietary 
information was acting outside the scope of his/her employment in 
revealing the information.
    (3) The State agrees to hold the Federal Government harmless for 
any violation by the State or its employees or contractors of the 
agreement to protect the confidentiality of proprietary data and 
information and samples.
    (4) The materials containing the proprietary data, information, and 
samples will remain the property of the Federal Government.
    (c) The data, information, and samples available for reproduction 
to the State(s) under an agreement must be related to leased lands. 
Data and information on unleased lands may be viewed but not copied or 
reproduced.
    (d) The State must return to us the materials containing the 
proprietary data, information, and samples when we ask for them or when 
the State no longer needs them.
    (e) Information received and knowledge gained by a State official 
under paragraph (d) of this section is subject to confidentiality 
requirements of:
    (1) The Act; and
    (2) The regulations at 30 CFR parts 580, 581, and 582.

Subpart E--Information Collection

Sec.  580.80  Paperwork Reduction Act statement--information 
collection.

    (a) The Office of Management and Budget (OMB) has approved the 
information collection requirements in this part under 44 U.S.C. 3501 
et seq. and assigned OMB control number 1010-0072. The title of this 
information collection is ``30 CFR part 580, Prospecting for Minerals 
other than Oil, Gas, and Sulphur on the Outer Continental Shelf.''
    (b) We may not conduct or sponsor, and you are not required to 
respond to, a collection of information unless it displays a currently 
valid OMB control number.

[[Page 64711]]

    (c) We use the information collected under this part to:
    (1) Evaluate permit applications and monitor scientific research 
activities for environmental and safety reasons.
    (2) Determine that prospecting does not harm resources, result in 
pollution, create hazardous or unsafe conditions, or interfere with 
other users in the area.
    (3) Approve reimbursement of certain expenses.
    (4) Monitor the progress and activities carried out under an OCS 
prospecting permit.
    (5) Inspect and select G&G data and information collected under an 
OCS prospecting permit.
    (d) Respondents are Federal OCS permittees and notice filers. 
Responses are mandatory or are required to obtain or retain a benefit. 
We will protect information considered proprietary under applicable law 
and under regulations at Sec.  580.70 and 30 CFR part 581.
    (e) Send comments regarding any aspect of the collection of 
information under this part, including suggestions for reducing the 
burden, to the Information Collection Clearance Officer, Bureau of 
Ocean Energy Management, 381 Elden Street, Herndon, VA 20170.

PART 581--LEASING OF MINERALS OTHER THAN OIL, GAS, AND SULPHUR IN 
THE OUTER CONTINENTAL SHELF

Subpart A--General
Sec.
581.0 Authority for information collection.
581.1 Purpose and applicability.
581.2 Authority.
581.3 Definitions.
581.4 Qualifications of lessees.
581.5 False statements.
581.6 Appeals.
581.7 Disclosure of information to the public.
581.8 Rights to minerals.
581.9 Jurisdictional controversies.
Subpart B--Leasing Procedures
581.11 Unsolicited request for a lease sale.
581.12 Request for OCS mineral information and interest.
581.13 Joint State/Federal coordination.
581.14 OCS mining area identification.
581.15 Tract size.
581.16 Proposed leasing notice.
581.17 Leasing notice.
581.18 Bidding system.
581.19 Lease term.
581.20 Submission of bids.
581.21 Award of leases.
581.22 Lease form.
581.23 Effective date of leases.
Subpart C--Financial Considerations
581.26 Payments.
581.27 Annual rental.
581.28 Royalty.
581.29 Royalty valuation.
581.30 Minimum royalty.
581.31 Overriding royalties.
581.32 Waiver, suspension, or reduction of rental, minimum royalty, 
or production royalty.
581.33 Bonds and bonding requirements.
Subpart D--Assignments and Lease Extensions
581.40 Assignment of leases or interests therein.
581.41 Requirements for filing for transfers.
581.42 Effect of assignment on particular lease.
581.43 Effect of suspensions on lease term.
Subpart E--Termination of Leases
581.46 Relinquishment of leases or parts of leases.
581.47 Cancellation of leases.

    Authority: 31 U.S.C. 9701, 43 U.S.C. 1334.

Subpart A--General

Sec.  581.0  Authority for information collection.

    The information collection requirements contained in part 581 have 
been approved by the Office of Management and Budget under 44 U.S.C. 
3507 and assigned clearance number 1010-0082. The information is being 
collected to determine if the applicant for a lease on the Outer 
Continental Shelf (OCS) is qualified to hold such a lease or to 
determine if a requested action is warranted. The information will be 
used to make those determinations. An applicant must respond to obtain 
or retain a benefit.

Sec.  581.1  Purpose and applicability.

    The purpose of these regulations is to establish procedures under 
which the Secretary of the Interior (Secretary) will exercise the 
authority granted to administer a leasing program for minerals other 
than oil, gas, and sulphur in the OCS. The rules in this part apply 
exclusively to leasing activities for minerals other than oil, gas, and 
sulphur in the OCS pursuant to the Act.

Sec.  581.2  Authority.

    The Act authorizes the Secretary to grant leases for any mineral 
other than oil, gas, and sulphur in any area of the OCS to the 
qualified persons offering the highest cash bonuses on the basis of 
competitive bidding upon such royalty, rental, and other terms and 
conditions as the Secretary may prescribe at the time of offering the 
area for lease (43 U.S.C. 1337(k)). The Secretary is to administer the 
leasing provisions of the Act and prescribe the rules and regulations 
necessary to carry out those provisions (43 U.S.C. 1334(a)).

Sec.  581.3  Definitions.

    When used in this part, the following terms shall have the 
following meaning:
    Act means the OCS Lands Act, as amended (43 U.S.C. 1331 et seq.).
    Adjacent State means with respect to any activity proposed, 
conducted, or approved under this part, any coastal State--
    (1) That is, or is proposed to be, receiving for processing, 
refining, or transshipping OCS mineral resources commercially recovered 
from the seabed;
    (2) That is used, or is scheduled to be used, as a support base for 
prospecting, exploration, testing, and mining activities; or
    (3) In which there is a reasonable probability of significant 
effect on land or water uses from such activity.
    Director means the Director of the Bureau of Ocean Energy 
Management (BOEM) of the U.S. Department of the Interior or an official 
authorized to act on the Director's behalf.
    Governor means the Governor of a State or the person or entity 
designated by, or pursuant to, State law to exercise the powers granted 
to such Governor pursuant to the Act.
    Lease means any form of authorization which is issued under section 
8 of the Act and which authorizes exploration for, and development and 
production of, minerals, or the area covered by that authorization, 
whichever is required by the context.
    Lessee means the person authorized by a lease, or an approved 
assignment thereof, to explore for and develop and produce the leased 
deposits in accordance with the regulations in this chapter. The term 
includes all persons holding that authority by or through the lessee.
    OCS mineral means a mineral deposit or accretion found on or below 
the surface of the seabed but does not include oil, gas, sulphur; salt 
or sand and gravel intended for use in association with the development 
of oil, gas, or sulphur; or source materials essential to production of 
fissionable materials which are reserved to the United States pursuant 
to section 12(e) of the Act.
    Outer Continental Shelf means all submerged lands lying seaward and 
outside of the area of lands beneath navigable waters as defined in 
section 2 of the Submerged Lands Act (43 U.S.C. 1301) and of which the 
subsoil and seabed appertain to the United States and are subject to 
its jurisdiction and control.
    Overriding royalty means a royalty created out of the lessee's 
interest which

[[Page 64712]]

is over and above the royalty reserved to the lessor in the original 
lease.
    Person means a citizen or national of the United States; an alien 
lawfully admitted for permanent residency in the United States as 
defined in 8 U.S.C. 1101(a)(20); a private, public, or municipal 
corporation organized under the laws of the United States or of any 
State or territory thereof; an association of such citizens, nationals, 
resident aliens or private, public, or municipal corporations, States, 
or political subdivisions of States; or anyone operating in a manner 
provided for by treaty or other applicable international agreements. 
The term does not include Federal Agencies.
    Secretary means the Secretary of the Interior or an official 
authorized to act on the Secretary's behalf.

Sec.  581.4  Qualifications of lessees.

    (a) In accordance with section 8(k) of the Act, leases shall be 
awarded only to qualified persons offering the highest cash bonus bid.
    (b) Mineral leases issued pursuant to section 8 of the Act may be 
held only by:
    (1) Citizens and nationals of the United States;
    (2) Aliens lawfully admitted for permanent residence in the United 
States as defined in 8 U.S.C. 1101(a)(20);
    (3) Private, public, or municipal corporations organized under the 
laws of the United States or of any State or of the District of 
Columbia or territory thereof; or
    (4) Associations of such citizens, nationals, resident aliens, or 
private, public, or municipal corporations, States, or political 
subdivisions of States.

Sec.  581.5  False statements.

    Under the provisions of 18 U.S.C. 1001, it is a crime punishable by 
up to 5 years imprisonment or a fine of $10,000, or both, for anyone 
knowingly and willfully to submit or cause to be submitted to any 
Agency of the United States any false or fraudulent statement(s) to any 
matters within the Agency's jurisdiction.

Sec.  581.6  Appeals.

    Any party adversely affected by a decision of a BOEM official made 
pursuant to the provisions of this part shall have the right of appeal 
pursuant to 30 CFR part 590, except as provided otherwise in Sec.  
581.21 of this part.

Sec.  581.7  Disclosure of information to the public.

    The Secretary shall make data and information available to the 
public in accordance with the requirements and subject to the 
limitations of the Act, the Freedom of Information Act (5 U.S.C. 552), 
and the implementing regulations (30 CFR parts 580, 582, and 43 CFR 
part 2).

Sec.  581.8  Rights to minerals.

    (a) Unless otherwise specified in the leasing notice, a lease for 
OCS minerals shall include rights to all minerals within the leased 
area except the following;
    (1) Minerals subject to rights granted by existing leases;
    (2) Oil;
    (3) Gas;
    (4) Sulphur;
    (5) Minerals produced in direct association with oil, gas, or 
sulphur;
    (6) Salt deposits which are identified in the leasing notice as 
being reserved;
    (7) Sand and gravel deposits which are identified in the leasing 
notice as being reserved; and
    (8) Source materials essential to production of fissionable 
materials which are reserved pursuant to section 12(a) of the Act.
    (b) When an OCS mineral lease issued under this part limits the 
minerals to which rights are granted, such lease shall include rights 
to minerals produced in direct association with the OCS mineral 
specified in the lease but not the rights to minerals specifically 
reserved.
    (c) The existence of an OCS mineral, oil and gas, or sulphur lease 
shall not preclude the issuance of a lease(s) for other OCS minerals in 
the same area. However, no OCS mineral lease shall authorize or permit 
the lessee thereunder to unreasonably interfere with or endanger 
operations under an existing OCS mineral, oil and gas, or sulphur 
lease.

Sec.  581.9  Jurisdictional controversies.

    In the event of a controversy between the United States and a State 
as to whether certain lands are subject to Federal or State 
jurisdiction (43 U.S.C. 1336), either the Governor or the Secretary may 
initiate negotiations in an attempt to settle the jurisdictional 
controversy. With the concurrence of the Attorney General, the 
Secretary may enter into an agreement with a State with respect to OCS 
mineral activities under the Act or under State authority and to 
payment and impounding of rents, royalties, and other sums and with 
respect to the offering of lands for lease pending settlement of the 
controversy.

Subpart B--Leasing Procedures

Sec.  581.11  Unsolicited request for a lease sale.

    (a) Any person may at any time request that OCS minerals be offered 
for lease. A request that OCS minerals be offered for lease shall be 
submitted to the Director and shall contain the following information:
    (1) The area to be offered for lease.
    (2) The OCS minerals of primary interest.
    (3) The available OCS mineral resource and environmental 
information pertaining to the area of interest to be offered for lease 
which supports the request.
    (b) Within 45 days after receipt of a request submitted under 
paragraph (a) of this section, the Director shall either initiate steps 
leading to the offer of OCS minerals for lease and notify the applicant 
of the action taken or inform the applicant of the reasons for not 
initiating steps leading to the offer of OCS minerals for lease.
    (c) Any interested party may at any time submit information to the 
Director concerning the scheduling of proposed lease sales of OCS 
minerals in any area of the OCS. Such information may include but not 
be limited to any of the following:
    (1) Benefits of conducting a lease sale in an area.
    (2) Costs of conducting a lease sale in an area.
    (3) Geohazards which could be encountered in an area.
    (4) Geological information about an area and mineral resource 
potential.
    (5) Environmental information about an area.
    (6) Information about known archaeological resources in an area.

Sec.  581.12  Request for OCS mineral information and interest.

    (a) When considering whether to offer OCS minerals for lease, the 
Secretary, upon the Department of the Interior's own initiative or as a 
result of a submission under Sec.  581.11, may request indications of 
interest in the leasing of a specific OCS mineral, a group of OCS 
minerals, or all OCS minerals in the area being considered for lease. 
Requests for information and interest shall be published in the Federal 
Register and may be published elsewhere.
    (b) States and local governments, industry, other Federal Agencies, 
and all interested parties (including the public) may respond to a 
request for information and interest. All information provided to the 
Secretary will be considered in the decision whether to proceed with 
additional

[[Page 64713]]

steps leading to the offering of OCS minerals for lease.
    (c) The Secretary may request specific information concerning the 
offering of a specific OCS mineral, a group of OCS minerals, or all OCS 
minerals in a broad area for lease or the offering of one or more 
discrete tracts which represent a minable orebody. The Secretary's 
request may ask for comments on OCS areas which have been determined to 
warrant special consideration and analysis. Requests may be for 
comments concerning geological conditions or archaeological resources 
on the seabed; multiple uses of the area proposed for leasing, 
including navigation, recreation and fisheries; and other 
socioeconomic, biological, and environmental information relating to 
the area proposed for leasing.

Sec.  581.13  Joint State/Federal coordination.

    (a) The Secretary may invite the adjacent State Governor(s) to join 
in, or the adjacent State Governor(s) may request that the Secretary 
join in, the establishment of a State/Federal task force or some other 
joint planning or coordination arrangement when industry interest 
exists for OCS mineral leasing or geological information appears to 
support the leasing of OCS minerals in specific areas. Participation in 
joint State/Federal task forces or other arrangements will afford the 
adjacent State Governor(s) opportunity for access to available data and 
information about the area; knowledge of progress made in the leasing 
process and of the results of subsequent exploration and development 
activities; facilitate the resolution of issues of mutual interest; and 
provide a mechanism for planning, coordination, consultation, and other 
activities which the Secretary and the Governor(s) may identify as 
contributing to the leasing process.
    (b) State/Federal task forces or other such arrangements are to be 
constituted pursuant to such terms and conditions (consistent with 
Federal law and these regulations) as the Secretary and the adjacent 
State Governor(s) may agree.
    (c) State/Federal task forces or other such arrangements will 
provide a forum which the Secretary and adjacent State Governor(s) may 
use for planning, consultation, and coordination on concerns associated 
with the offering of OCS minerals other than oil, gas, or sulphur for 
lease.
    (d) With respect to the activities authorized under these 
regulations each State/Federal task force may make recommendations to 
the Secretary and adjacent State Governor(s) concerning:
    (1) The identification of areas in which OCS minerals might be 
offered for lease;
    (2) The potential for conflicts between the exploration and 
development of OCS mineral resources, other users and uses of the area, 
and means for resolution or mitigation of these conflicts;
    (3) The economic feasibility of developing OCS mineral resources in 
the area proposed for leasing;
    (4) Potential environmental problems and measures that might be 
taken to mitigate these problems;
    (5) Development of guidelines and procedures for safe, 
environmentally responsible exploration and development practices; and
    (6) Other issues of concern to the Secretary and adjacent State 
Governor(s).
    (e) State/Federal task forces or other such arrangements might also 
be used to conduct or oversee research, studies, or reports (e.g., 
Environmental Impact Statements).

Sec.  581.14  OCS mining area identification.

    The Secretary, after considering the available OCS mineral 
resources and environmental data and information, the recommendation of 
any joint State/Federal task force established pursuant to Sec.  581.13 
of this part, and the comments received from interested parties, shall 
select the tracts to be considered for offering for lease. The selected 
tracts will be considered in the environmental analysis conducted for 
the proposed lease offering.

Sec.  581.15  Tract size.

    The size of the tracts to be offered for lease shall be as 
determined by the Secretary and specified in the leasing notice. It is 
intended that tracts offered for lease be sufficiently large to include 
potentially minable OCS mineral orebodies. When the presence of any 
minable orebody is unknown and additional prospecting is needed to 
discover and delineate OCS minerals, the size of tracts specified in 
the leasing notice may be relatively large.

Sec.  581.16  Proposed leasing notice.

    (a) Prior to offering OCS minerals in an area for lease, the 
Director shall assess the available information including 
recommendations of any joint State/Federal task force established 
pursuant to Sec.  581.13 of this part to determine lease sale 
procedures to be prescribed and to develop a proposed leasing notice 
which sets out the proposed primary term of the OCS mineral leases to 
be offered; lease stipulations including measures to mitigate 
potentially adverse impacts on the environment; and such rental, 
royalty, and other terms and conditions as the Secretary may prescribe 
in the leasing notice.
    (b) The proposed leasing notice shall be sent to the Governor(s) of 
any adjacent State(s), and a Notice of its availability shall be 
published in the Federal Register at least 60 days prior to the 
publication of the leasing notice.
    (c) Written comments of the adjacent State Governor(s) submitted 
within 60 days after publication of the Notice of Availability of the 
proposed leasing notice shall be considered by the Secretary.
    (d) Prior to publication of the leasing notice, the Secretary shall 
respond in writing to the comments of the adjacent State Governor(s) 
stating the reasons for accepting or rejecting the Governor's 
recommendations, or for implementing any alternative mutually 
acceptable approach identified in consultation with the Governor(s) as 
a means to provide a reasonable balance between the National interest 
and the well being of the citizens of the adjacent State.

Sec.  581.17  Leasing notice.

    (a) The Director shall publish the leasing notice in the Federal 
Register at least 30 days prior to the date that OCS minerals will be 
offered for lease. The leasing notice shall state whether oral or 
sealed bids or a combination thereof will be used; the place, date, and 
time at which sealed bids shall be filed; and the place, date, and time 
at which sealed bids shall be opened and/or oral bids received. The 
leasing notice shall contain or reference a description of the tract(s) 
to be offered for lease; specify the mineral(s) to be offered for lease 
(if less than all OCS minerals are being offered); specify the period 
of time the primary term of the lease shall cover; and any 
stipulation(s), term(s), and condition(s) of the offer to lease (43 
U.S.C. 1337(k)).
    (b) The leasing notice shall contain a reference to the OCS 
minerals lease form which shall be issued to successful bidders.
    (c) The leasing notice shall specify the terms and conditions 
governing the payment of the winning bid.

Sec.  581.18  Bidding system.

    (a) The OCS minerals shall be offered by competitive, cash bonus 
bidding under terms and conditions specified in the leasing notice and 
in accordance with all applicable laws and regulations.
    (b)(1) When the leasing notice specifies the use of sealed bids, 
such bids received in response to the leasing notice shall be opened at 
the place, date,

[[Page 64714]]

and time specified in the leasing notice. The sole purpose of opening 
bids is to publicly announce and record the bids received, and no bids 
shall be accepted or rejected at that time.
    (2) The Secretary reserves the right to reject any and all sealed 
bids received for any tract, regardless of the amount offered.
    (3) In the event the highest bids are tie bids when using sealed 
bidding procedures, the tied bidders may be permitted to submit oral 
bids to determine the highest cash bonus bidder.
    (c)(1) When the leasing notice specifies the use of oral bids, oral 
bids shall be received at the place, time, and date and in accordance 
with the procedures specified in the leasing notice.
    (2) The Secretary reserves the right to reject all oral bids 
received for any tract, regardless of the amount offered.
    (d) When the leasing notice specifies the use of deferred cash 
bonus bidding, bids shall be received in accordance with paragraph (b) 
or (c) of this section, as appropriate. The high bid will be determined 
based upon the net present value of each total bid. The appropriate 
discount rate will be specified in the leasing notice. High bidders 
using the deferred bonus option shall pay a minimum of 20 percent of 
the cash bonus bid prior to lease issuance. At least a total of 60 
percent of the cash bonus bid shall be due on or before the 5th 
anniversary of the lease, and payment of the remainder of the cash 
bonus bid shall be due on the 10th anniversary of the lease. The lessee 
shall submit a bond guaranteeing payment of the deferred portion of the 
bonus, in accordance with Sec.  581.33.

Sec.  581.19  Lease term.

    An OCS mineral lease for OCS minerals other than sand and gravel 
shall be for a primary term of not less than 20 years as stipulated in 
the leasing notice. The primary lease term for each OCS mineral shall 
be determined based on exploration and development requirements for the 
OCS minerals being offered by the Secretary. An OCS mineral lease for 
sand and gravel shall be for a primary term of 10 years unless 
otherwise stipulated in the leasing notice. A lease will continue 
beyond the specified primary term for so long thereafter as leased OCS 
minerals are being produced in accordance with an approved mining 
operation or the lessee is otherwise in compliance with provisions of 
the lease and the regulations in this chapter under which a lessee can 
earn continuance of the OCS mineral lease in effect.

Sec.  581.20  Submission of bids.

    (a) If the bidder is an individual, a statement of citizenship 
shall accompany the bid.
    (b) If the bidder is an association (including a partnership), the 
bid shall be accompanied by a certified statement indicating the State 
in which it is registered and that the association is authorized to 
hold mineral leases on the OCS, or appropriate reference to statements 
or records previously submitted to a BOEM OCS office (including 
material submitted in compliance with prior regulations).
    (c) If the bidder is a corporation, the bid shall be accompanied by 
the following information:
    (1) Either a statement certified by the corporate Secretary or 
Assistant Secretary over the corporate seal showing the State in which 
it was incorporated and that it is authorized to hold mineral leases on 
the OCS or appropriate reference to statements or record previously 
submitted to a BOEM OCS office (including material submitted in 
compliance with prior regulations).
    (2) Evidence of authority of persons signing to bind the 
corporation. Such evidence may be in the form of a certified copy of 
either the minutes of the board of directors or of the bylaws 
indicating that the person signing has authority to do so, or a 
certificate to that effect signed by the Secretary or Assistant 
Secretary of the corporation over the corporate seal, or appropriate 
reference to statements or records previously submitted to a BOEM OCS 
office (including material submitted in compliance with prior 
regulations). Bidders are advised to keep their filings current.
    (3) The bid shall be executed in conformance with corporate 
requirements.
    (d) Bidders should be aware of the provisions of 18 U.S.C. 1860, 
which prohibits unlawful combination or intimidation of bidders.
    (e) When sealed bidding is specified in the leasing notice, a 
separate sealed bid shall be submitted for each bid unit that is bid 
upon as described in the leasing notice. A bid may not be submitted for 
less than a bidding unit identified in the leasing notice.
    (f) When oral bidding is specified in the leasing notice, 
information which must accompany a bid pursuant to paragraph (a), (b), 
or (c) of this section, shall be presented to BOEM at the lease sale 
prior to the offering of an oral bid.

Sec.  581.21  Award of leases.

    (a)(1) The decision of the Director on bids shall be the final 
action of the Department, subject only to reconsideration by the 
Secretary, pursuant to a written request in accordance with paragraph 
(a)(2) of this section. The delegation of review authority to the 
Office of Hearings and Appeals shall not be applicable to decisions on 
high bids for leases in the OCS.
    (2) Any bidder whose bid is rejected by the Director may file a 
written request for reconsideration with the Secretary within 15 days 
of notice of rejection, accompanied by a statement of reasons with a 
copy to the Director. The Secretary shall respond in writing either 
affirming or reversing the decision.
    (b) Written notice of the Director's action in accepting or 
rejecting bids shall be transmitted promptly to those bidders whose 
deposits have been held. If a bid is accepted, such notice shall 
transmit three copies of the lease form to the successful bidder. As 
provided in Sec.  581.26 of this part, the bidder shall, not later than 
the 10th business day after receipt of the lease, execute the lease, 
pay the first year's rental, and unless payment of a portion of the bid 
is deferred, pay the balance of the bonus bid. When payment of a 
portion of the bid is deferred, the successful bidder shall also file a 
bond to guarantee payment of the deferred portion as required in Sec.  
581.33. Deposits shall be refunded on high bids subsequently rejected. 
When three copies of the lease have been executed by the successful 
bidder and returned to the Director, the lease shall be executed on 
behalf of the United States; and one fully executed copy shall be 
transmitted to the successful bidder.
    (c) If the successful bidder fails to execute the lease within the 
prescribed time or to otherwise comply with the applicable regulations, 
the successful bidder's deposit shall be forfeited and disposed of in 
the same manner as other receipts under the Act.
    (d) If, before the lease is executed on behalf of the United 
States, the land which would be subject to the lease is withdrawn or 
restricted from leasing, the deposit shall be refunded.
    (e) If the awarded lease is executed by an agent acting on behalf 
of the bidder, the bidder shall submit with the executed lease, 
evidence that the agent is authorized to act on behalf of the bidder.

Sec.  581.22  Lease form.

    The OCS mineral leases shall be issued on the lease form prescribed 
by the Secretary in the leasing notice.

[[Page 64715]]

Sec.  581.23  Effective date of leases.

    Leases issued under the regulations in this part shall be dated and 
become effective as of the first day of the month following the date 
leases are signed on behalf of the lessor except that, upon written 
request, a lease may be dated and become effective as of the first day 
of the month within which it is signed on behalf of the lessor.

Subpart C--Financial Considerations

Sec.  581.26  Payments.

    (a) For sealed bids, a bonus bid deposit of a specified percentage 
of the total amount bid is required to be submitted with the bid. The 
percentage of bonus bid required to be deposited will be specified in 
the leasing notice. The remittance may be made in cash or by Federal 
Reserve check, commercial check, bank draft, money order, certified 
check, or cashier's check made payable to ``Department of the 
Interior--BOEM.'' Payment of this portion of the bonus bid may not be 
made by Electronic Funds Transfer.
    (b) For oral bids, a bonus bid deposit of a specified percentage of 
the total amount bid must be submitted to the official designated in 
the leasing notice following the completion of the oral bidding. The 
percentage of bonus bid required to be deposited will be specified in 
the leasing notice. Payment of this portion of the bonus bid must be 
made by Electronic Fund Transfer within the timeframe specified in the 
leasing notice.
    (c) The deposit received from high bidders will be placed in a 
Treasury account pending acceptance or rejection of the bid. Other bids 
submitted under paragraph (a) of this section will be returned to the 
bidders. If the high bid is subsequently rejected, an amount equal to 
that deposited with the high bid will be returned according to 
applicable regulations.
    (d) The balance of the winning bonus bid and all rentals and 
royalties must be paid in accordance with the terms and conditions of 
this part, the Leasing Notice, and Subchapter A of this chapter.
    (e) For each lease issued pursuant to this subpart, there shall be 
one person identified who shall be solely responsible for all payments 
due and payable under the provisions of the lease. The single 
responsible person shall be designated as the payor for the lease and 
shall be so identified on the Solid Minerals Production and Royalty 
Report (P&R) (Form ONRR-4430) in accordance with 30 CFR 1210.201 of 
this title. The designated person shall be responsible for all bonus, 
rental, and royalty payments.
    (f) Royalty shall be computed at the rate specified in the leasing 
notice, and paid in value unless the Secretary elects to have the 
royalty delivered in kind.
    (g) For leases which provide for minimum royalty payments, each 
lessee shall pay the minimum royalty specified in the lease at the end 
of each lease year beginning with the lease year in which production 
royalty is paid (whether the full amount specified in the lease or 
[frac12] the amount specified in the lease pursuant to Sec.  581.28(b) 
on this part) of OCS minerals produced (sold, transferred, used, or 
otherwise disposed of) from the leasehold.
    (h)(1) Unless stated otherwise in the lease, product valuation will 
be in accordance with the regulations in part 1206 of chapter XII. The 
value used in the computation of royalty shall be determined by the 
Director of the Office of Natural Resources Revenue. The value, for 
royalty purposes, shall be the gross proceeds received by the lessee 
for produced substances at the point the product is produced and placed 
in its first marketable condition, consistent with prevailing practices 
in the industry. In establishing the value, the Director shall 
consider, in this order:
    (i) The price received by the lessee;
    (ii) Commodity and spot market transactions;
    (iii) Any other valuation method proposed by the lessee and 
approved by the Director; and
    (iv) Value or cost netback.
    (2) For non-arm's length transactions, the first benchmark will 
only be accepted if it is not less than the second benchmark.
    (i) All payors must submit payments and payment forms and maintain 
auditable records in accordance with 30 CFR chapter XII, Subchapter A--
Natural Resources Revenue.

Sec.  581.27  Annual rental.

    (a) The annual lease rental shall be due and payable in accordance 
with the provisions of this section. No rental shall be due or payable 
under a lease commencing with the first lease anniversary date 
following the commencement of royalty payments on leasehold production 
computed on the basis of the royalty rate specified in the lease except 
that annual rental shall be due for any year in which production from 
the leasehold is not subject to royalty pursuant to Sec.  581.28.
    (b) Unless otherwise specified in the leasing notice and 
subsequently issued lease, no annual rental payment shall be due during 
the first 5 years in the life of a lease.
    (c) The leasee shall pay an annual rental in the amount specified 
in the leasing notice and subsequently issued lease not later than the 
last day prior to the commencement of the rental year.
    (d) A rental adjustment schedule and amount may be specified in a 
leasing notice and subsequently issued lease when a variance is 
warranted by geologic, geographic, technical, or economic conditions.

Sec.  581.28  Royalty.

    (a) The royalty due the lessor on OCS minerals produced (i.e., 
sold, transferred, used, or otherwise disposed of) from a lease shall 
be set out in a separate schedule attached to and made a part of each 
lease and shall be as specified in the leasing notice. The royalty due 
on production shall be based on a percentage of the value or amount of 
the OCS mineral(s) produced, a sum assessed per unit of product, or 
other such method as the Secretary may prescribe in the leasing notice. 
When the royalty specified is a sum assessed per unit of product, the 
amount of the royalty shall be subject to an annual adjustment based on 
changes in the appropriate price index, when specified in the leasing 
notice. When the royalty is specified as a percentage of the value or 
amount of the OCS minerals produced, the Secretary will notify the 
lessee when and where royalty is to be delivered in kind. Unless stated 
otherwise in the lease, product valuation will be in accordance with 
the regulations in part 1206 of chapter XII. The value used in the 
computation of royalty shall be determined by the Director of the 
Office of Natural Resources Revenue.
    (b) When prescribed in the leasing notice and subsequently issued 
lease, royalty due on OCS minerals produced from a leasehold will be 
reduced for up to any 5 consecutive years, as specified by the lessee 
prior to the commencement of production, during the 1st through 15th 
year in the life of the lease. No royalty shall be due in any year of 
the specified 5-year period that occurs during the 1st through 10th 
years in the life of the lease, and a royalty of one-half the amount 
specified in the lease shall be due in any year of the specified 5-year 
period that occurs in the 11th through 15th year in the life of the 
lease. The lessee shall pay the amount specified in the lease rental 
for any royalty free year. The minimum royalty specified in the lease 
shall apply during any year of reduced royalty.

Sec.  581.29  Royalty valuation.

    Unless stated otherwise in the leasing notice and subsequently 
issued lease,

[[Page 64716]]

product valuation will be in accordance with the regulations in part 
1206 of chapter XII. The value used in the computation of royalty shall 
be determined by the Director of the Office of Natural Resources 
Revenue.

Sec.  581.30  Minimum royalty.

    Unless otherwise specified in the leasing notice, each lease issued 
pursuant to the regulations in this part shall require the payment of a 
specified minimum annual royalty beginning with the year in which OCS 
minerals are produced (sold, transferred, used, or otherwise disposed 
of) from the leasehold except that the annual rentals shall apply 
during any year that royalty free production is in effect pursuant to 
Sec.  581.28(b). Minimum royalty payments shall be offset by royalty 
paid on production during the lease year. Minimum royalty payments are 
due at the beginning of the lease year and payable by the end of the 
month following the end of the lease year for which they are due.

Sec.  581.31  Overriding royalties.

    (a) Subject to the approval of the Secretary, an overriding royalty 
interest may be created by an assignment pursuant to section 8(e) of 
the Act. The Secretary may deny approval of an assignment which creates 
an overriding royalty on a lease whenever that denial is determined to 
be in the interest of conservation, necessary to prevent premature 
abandonment of a producing mine, or to make possible the mining of 
economically marginal or low-grade ore deposits. In any case, the total 
of applicable overriding royalties may not exceed 2.5 percent or one-
half the base royalty due the Federal Government, whichever is less.
    (b) No transfer or agreement may be made which creates an 
overriding royalty interest unless the owner of that interest files an 
agreement in writing that such interest is subject to the limitations 
provided in Sec.  581.30 of this part, paragraph (a) of this section, 
and Sec.  581.32 of this part.

Sec.  581.32  Waiver, suspension, or reduction of rental, minimum 
royalty, or production royalty.

    (a) The Secretary may waive, suspend, or reduce the rental, minimum 
royalty, and/or production royalty prescribed in a lease for a 
specified time period when the Secretary determines that it is in the 
National interest, it will result in the conservation of natural 
resources of the OCS, it will promote development, or the mine cannot 
be successfully operated under existing conditions.
    (b) An application for waiver, suspension, or reduction of rental, 
minimum royalty, or production royalty under paragraph (a) of this 
section shall be filed in duplicate with the Director. The application 
shall contain the serial number(s) of the lease(s), the name of the 
lessee(s) of record, and the operator(s) if applicable. The application 
shall either:
    (1)(i) Show the location and extent of all mining operations and a 
tabulated statement of the minerals mined and subject to royalty for 
each of the last 12 months immediately prior to filing the application:
    (ii) Contain a detailed statement of expenses and costs of 
operating the lease, the income from the sale of any lease products, 
and the amount of all overriding royalties and payments out of 
production paid to others than the United States; and
    (iii) All facts showing whether or not the mine(s) can be 
successfully operated under the royalty fixed in the lease; or
    (2) If no production has occurred from the lease, show that the 
lease cannot be successfully operated under the rental, royalty, and 
other conditions specified in the lease.
    (c) The applicant for a waiver, suspension, or reduction under this 
section shall file documentation that the lessee and the royalty 
holders agree to a reduction of all other royalties from the lease so 
that the aggregate of all other royalties does not exceed one-half the 
amount of the reduced royalties that would be paid to the United 
States.

Sec.  581.33  Bonds and bonding requirements.

    (a) When the leasing notice specifies that payment of a portion of 
the bonus bid can be deferred, the lessee shall be required to submit a 
surety or personal bond to guarantee payment of a deferred portion of 
the bid. Upon the payment of the full amount of the cash bonus bid, the 
lessee's bond will be released.
    (b) All bonds to guarantee payment of the deferred portion of the 
high cash bonus bid furnished by the lessee must be in a form or on a 
form approved by the Associate Director for BOEM. A single copy of the 
required form is to be executed by the principal or, in the case of 
surety bonds, by both the principal and an acceptable surety.
    (1) Only those surety bonds issued by qualified surety companies 
approved by the Department of the Treasury shall be accepted (see 
Department of the Treasury Circular No. 570 and any supplemental or 
replacement circulars).
    (2) Personal bonds shall be accompanied by a cashier's check, 
certified check, or negotiable U.S. Treasury bonds of an equal value to 
the amount specified in the bond. Negotiable Treasury bonds shall be 
accompanied by a proper conveyance of full authority to the Director to 
sell such securities in case of default in the performance of the terms 
and conditions of the lease.
    (c) Prior to the commencement of any activity on a lease(s), the 
lessee shall submit a surety or personal bond as described in Sec.  
582.40 of this title. Prior to the approval of a Delineation, Testing, 
or Mining Plan, the bond amount shall be adjusted, if appropriate, to 
cover the operations and activities described in the proposed plan.

Subpart D--Assignments and Lease Extensions

Sec.  581.40  Assignment of leases or interests therein.

    (a) Subject to the approval of the Secretary, a lease may be 
assigned, in whole or in part, pursuant to section 8(e) of the Act to 
anyone qualified to hold a lease.
    (b) Any approved assignment shall be deemed to be effective on the 
first day of the lease month following the date that it is submitted to 
the Director for approval unless by written request the parties request 
that the effective date be the first of the month in which the Director 
approves the assignment.
    (c) The assignor shall be liable for all obligations under the 
lease occurring prior to the effective date of an assignment.
    (d) The assignee shall be liable for all obligations under the 
lease occurring on or after the effective date of an assignment and 
shall comply with all terms and conditions of the lease and applicable 
regulations issued under the Act.

Sec.  581.41  Requirements for filing for transfers.

    (a)(1) All instruments of transfer of a lease or of an interest 
therein including subleases and assignments of record interest shall be 
filed in triplicate for approval within 90 days from the date of final 
execution. They shall include a statement over the transferee's own 
signature with respect to citizenship and qualifications similar to 
that required of a lessee and shall contain all of the terms and 
conditions agreed upon by the parties thereto.
    (2) An application for approval of any instrument required to be 
filed will not be accepted unless a nonrefundable fee of $50 is paid 
electronically through Pay.gov at: https://www.pay.gov/paygov/ and a 
copy of the Pay.gov confirmation receipt page is included with your 
application. For any document you are not required to file by

[[Page 64717]]

these regulations but which you submit for record purposes, you must 
also pay electronically through Pay.gov a nonrefundable fee of $50 per 
lease affected, and you must include a copy of the Pay.gov confirmation 
receipt page with your document. Such documents may be rejected at the 
discretion of the authorized officer.
    (b) An attorney in fact signing on behalf of the holder of a lease 
or sublease, shall furnish evidence of authority to execute the 
assignment or application for approval and the statement required by 
Sec.  581.20 of this part.
    (c) Where an assignment creates separate leases, a bond shall be 
furnished for each of the resulting leases in the amount prescribed in 
Sec.  582.40 of this title. Where an assignment does not create 
separate leases, the assignee, if the assignment so provides and the 
surety consents, may become a joint principal on the bond with the 
assignor.
    (d) An heir or devisee of a deceased holder of a lease or any 
interest therein shall be recognized as the lawful successor to such 
lease or interest if evidence of status as an heir or devisee is 
furnished in the form of:
    (1) A certified copy of an appropriate order or decree of the court 
having jurisdiction over the distribution of the estate, or
    (2) If no court action is necessary, the statement of two 
disinterested persons having knowledge of the fact or a certified copy 
of the will.
    (e) The heirs or devisee shall file statements that they are the 
persons named as successors to the estate with evidence of their 
qualifications to hold such lease or interest therein.
    (f) In the event an heir or devisee is unable to qualify to hold 
the lease or interest, the heir or devisee shall be recognized as the 
lawful successor of the deceased and be entitled to hold the lease for 
a period not to exceed 2 years from the date of death of the 
predecessor in interest.
    (g) Each obligation under any lease and under the regulations in 
this part shall inure to the heirs, executors, administrators, 
successors, or assignees of the lease.

Sec.  581.42  Effect of assignment on particular lease.

    (a) When an assignment is made of all the record title to a portion 
of the acreage in a lease, the assigned and retained portions of the 
lease area become segregated into separate and distinct leases. In such 
a case, the assignee becomes a lessee of the Government as to the 
segregated tract that is the subject of the assignment and is bound by 
the terms of the lease as though the lease had been obtained from the 
United States in the assignee's own name, and the assignment, after its 
approval, shall be the basis of a new record. Royalty, minimum royalty, 
and annual rental provisions of the lease shall apply separately to 
each segregated portion.
    (b) Each lease of an OCS mineral created by the segregation of a 
lease under paragraph (a) of this section shall continue in full force 
and effect for the remainder of the primary term of the original lease 
and so long thereafter as minerals are produced from the portion of the 
lease created by segregation in accordance with operations approved by 
the Director or the lessee is otherwise in compliance with provisions 
of the lease or regulations for earning the continuation of the lease 
in effect.

Sec.  581.43  Effect of suspensions on lease term.

    (a) If the BSEE Director orders the suspension of either operations 
or production, or both, with respect to any lease in its primary term, 
the primary term of the lease shall be extended by a period of time 
equivalent to the period of the directed suspension.
    (b) If the BSEE Director orders or approves the suspension of 
either operations or production, or both, with respect to any lease 
that is in force beyond its primary term, the term of the lease shall 
not be deemed to expire so long as the suspension remains in effect.

Subpart E--Termination of Leases

Sec.  581.46  Relinquishment of leases or parts of leases.

    (a) A lease or any part thereof may be surrendered by the record 
title holder by filing a written relinquishment with the Director. A 
relinquishment shall take effect on the date it is filed subject to the 
continued obligation of the lessee and the surety to:
    (1) Make all payments due, including any accrued rentals and 
royalties; and
    (2) Abandon all operations, remove all facilities, and clear the 
land to be relinquished to the satisfaction of the Director.
    (b) Upon relinquishment of a lease, the data and information 
submitted under the lease will no longer be held confidential and will 
be available to the public.

Sec.  581.47  Cancellation of leases.

    (a) Whenever the owner of a nonproducing lease fails to comply with 
any of the provisions of the Act, the lease, or the regulations issued 
under the Act, and the default continues for a period of 30 days after 
mailing of notice by registered or certified letter to the lease owner 
at the owner's record post office address, the Secretary may cancel the 
lease pursuant to section 5(c) of the Act, and the lessee shall not be 
entitled to compensation. Any such cancellation is subject to judicial 
review as provided by section 23(b) of the Act.
    (b) Whenever the owner of any producing lease fails to comply with 
any of the provisions of the Act, the lease, or the regulations issued 
under the Act, the Secretary may cancel the lease only after judicial 
proceedings pursuant to section 5(d) of the Act, and the lessee shall 
not be entitled to compensation.
    (c) Any lease issued under the Act, whether producing or not, may 
be canceled by the Secretary upon proof that it was obtained by fraud 
or misrepresentation and after notice and opportunity to be heard has 
been afforded to the lessee.
    (d) The Secretary may cancel a lease in accordance with the 
following:
    (1) Cancellation may occur at any time if the Secretary determines 
after a hearing that:
    (i) Continued activity pursuant to such lease would probably cause 
serious harm or damage to life (including fish and other aquatic life), 
to property, to any mineral (in areas leased or not leased), to the 
National security or defense, or to the marine, coastal, or human 
environment;
    (ii) The threat of harm or damage will not disappear or decrease to 
an acceptable extent within a reasonable period of time; and
    (iii) The advantages of cancellation outweigh the advantages of 
continuing such lease in force;
    (2) Cancellation shall not occur unless and until operations under 
such lease shall have been under suspension or temporary prohibition by 
the Secretary, with due extension of any lease term continuously for a 
period of 5 years, or for a lesser period upon request of the lessee; 
and
    (3) Cancellation shall entitle the lessee to receive such 
compensation as is shown to the Secretary as being equal to the lesser 
of:
    (i) The fair value of the canceled rights as of the date of 
cancellation, taking into account both anticipated revenues from the 
lease and anticipated costs, including costs of compliance with all 
applicable regulations and operating orders, liability for cleanup 
costs or damages, or both, and all other costs reasonably anticipated 
on the lease, or
    (ii) The excess, if any, over the lessee's revenues from the lease 
(plus interest thereon from the date of receipt

[[Page 64718]]

to date of reimbursement) of all consideration paid for the lease and 
all direct expenditures made by the lessee after the date of issuance 
of such lease and in connection with exploration or development, or 
both, pursuant to the lease (plus interest on such consideration and 
such expenditures from date of payment to date of reimbursement), 
except that in the case of joint leases which are canceled due to the 
failure of one or more partners to exercise due diligence, the innocent 
parties shall have the right to seek damages for such loss from the 
responsible party or parties and the right to acquire the interests of 
the negligent party or parties and be issued the lease in question.
    (iii) The lessee shall not be entitled to compensation where one of 
the following circumstances exists when a lease is canceled:
    (A) A producing lease is forfeited or is canceled pursuant to 
section (5)(d) of the Act;
    (B) A Testing Plan or Mining Plan is disapproved because of the 
lessee's failure to demonstrate compliance with the requirements of 
applicable Federal Law; or
    (C) The lessee(s) of a nonproducing lease fails to comply with a 
provision of the Act, the lease, or regulations issued under the Act, 
and the noncompliance continues for a period of 30 days or more after 
the mailing of a notice of noncompliance by registered or certified 
letter to the lessee(s).

PART 582--OPERATIONS IN THE OUTER CONTINENTAL SHELF FOR MINERALS 
OTHER THAN OIL, GAS, AND SULPHUR

Subpart A--General
Sec.
582.0 Authority for information collection.
582.1 Purpose and authority.
582.2 Scope.
582.3 Definitions.
582.4 Opportunities for review and comment.
582.5 Disclosure of data and information to the public.
582.6 Disclosure of data and information to an adjacent State.
582.7 Jurisdictional controversies.
Subpart B--Jurisdiction and Responsibilities of Director
582.10 Jurisdiction and responsibilities of Director.
582.11 Director's authority.
582.12 Director's responsibilities.
582.13 [Reserved]
582.14 Noncompliance, remedies, and penalties.
582.15 Cancellation of leases.
Subpart C--Obligations and Responsibilities of Lessees
582.20 Obligations and responsibilities of lessees.
582.21 Plans, general.
582.22 Delineation Plan.
582.23 Testing Plan.
582.24 Mining Plan.
582.25 Plan modification.
582.26 Contingency Plan.
582.27 Conduct of operations.
582.28 Environmental protection measures.
582.29 Reports and records.
582.30 Right of use and easement.
582.31 [Reserved]
Subpart D--Payments
582.40 Bonds.
582.41 Method of royalty calculation.
582.42 Payments.
Subpart E--Appeals
582.50 Appeals.

    Authority: 43 U.S.C. 1334.

Subpart A--General

Sec.  582.0  Authority for information collection.

    The information collection requirements in this part have been 
approved by the Office of Management and Budget under 44 U.S.C. 3507 
and assigned clearance number 1010-0081. The information is being 
collected to inform the Bureau of Ocean Energy Management (BOEM) of 
general mining operations in the Outer Continental Shelf (OCS). The 
information will be used to ensure that operations are conducted in a 
safe and environmentally responsible manner in compliance with 
governing laws and regulations. The requirement to respond is 
mandatory.

Sec.  582.1  Purpose and authority.

    (a) The Act authorizes the Secretary to prescribe such rules and 
regulations as may be necessary to carry out the provisions of the Act 
(43 U.S.C. 1334). The Secretary is authorized to prescribe and amend 
regulations that the Secretary determines to be necessary and proper in 
order to provide for the prevention of waste, conservation of the 
natural resources of the OCS, and the protection of correlative rights 
therein. In the enforcement of safety, environmental, and conservation 
laws and regulations, the Secretary is authorized to cooperate with 
adjacent States and other Departments and Agencies of the Federal 
Government.
    (b) Subject to the supervisory authority of the Secretary, and 
unless otherwise specified, the regulations in this part shall be 
administered by the Director of BOEM.

Sec.  582.2  Scope.

    The rules and regulations in this part apply as of their effective 
date to all operations conducted under a mineral lease for OCS minerals 
other than oil, gas, or sulphur issued under the provisions of section 
8(k) of the Act.

Sec.  582.3  Definitions.

    When used in this part, the following terms shall have the meaning 
given below:
    Act means the OCS Lands Act, as amended (43 U.S.C. 1331 et seq.).
    Adjacent State means with respect to any activity proposed, 
conducted, or approved under this part, any coastal State:
    (1) That is, or is proposed to be, receiving for processing, 
refining, or transshipment OCS mineral resources commercially recovered 
from the seabed;
    (2) That is used, or is scheduled to be used, as a support base for 
prospecting, exploration, testing, or mining activities; or
    (3) In which there is a reasonable probability of significant 
effect on land or water uses from such activity.
    Contingency Plan means a plan for action to be taken in emergency 
situations.
    Data means geological and geophysical (G&G) facts and statistics or 
samples which have not been analyzed, processed, or interpreted.
    Development means those activities which take place following the 
discovery of minerals in paying quantities including geophysical 
activities, drilling, construction of offshore facilities, and 
operation of all onshore support facilities, which are for the purpose 
of ultimately producing the minerals discovered.
    Director means the Director of BOEM of the U.S. Department of the 
Interior or an official authorized to act on the Director's behalf.
    Exploration means the process of searching for minerals on a lease 
including:
    (1) Geophysical surveys where magnetic, gravity, seismic, or other 
systems are used to detect or imply the presence of minerals;
    (2) Any drilling including the drilling of a borehole in which the 
discovery of a mineral other than oil, gas, or sulphur is made and the 
drilling of any additional boreholes needed to delineate any mineral 
deposits; and
    (3) The taking of sample portions of a mineral deposit to enable 
the lessee to determine whether to proceed with development and 
production.
    Geological sample means a collected portion of the seabed, the 
subseabed, or

[[Page 64719]]

the overlying waters (when obtained for geochemical analysis) acquired 
while conducting postlease mining activities.
    Governor means the Governor of a State or the person or entity 
designated by, or pursuant to, State law to exercise the power granted 
to a Governor.
    Information means G&G data that have been analyzed, processed, or 
interpreted.
    Lease means one of the following, whichever is required by the 
context: Any form of authorization which is issued under section 8 or 
maintained under section 6 of the Acts and which authorizes exploration 
for, and development and production of, specific minerals; or the area 
covered by that authorization.
    Lessee means the person authorized by a lease, or an approved 
assignment thereof, to explore for and develop and produce the leased 
deposits in accordance with the regulations in this chapter. The term 
includes all parties holding that authority by or through the lessee.
    Major Federal action means any action or proposal by the Secretary 
which is subject to the provisions of section 102(2)(C) of the National 
Environmental Policy Act (NEPA) (i.e., an action which will have a 
significant impact on the quality of the human environment requiring 
preparation of an Environmental Impact Statement (EIS) pursuant to 
section 102(2)(C) of NEPA).
    Marine environment means the physical, atmospheric, and biological 
components, conditions, and factors which interactively determine the 
productivity, state, condition, and quality of the marine ecosystem, 
including the waters of the high seas, the contiguous zone, 
transitional and intertidal areas, salt marshes, and wetlands within 
the coastal zone and on the OCS.
    Minerals include oil, gas, sulphur, geopressured-geothermal and 
associated resources, and all other minerals which are authorized by an 
Act of Congress to be produced from ``public lands'' as defined in 
section 103 of the Federal Land Policy and Management Act of 1976.
    OCS mineral means any mineral deposit or accretion found on or 
below the surface of the seabed but does not include oil, gas, or 
sulphur; salt or sand and gravel intended for use in association with 
the development of oil, gas, or sulphur; or source materials essential 
to production of fissionable materials which are reserved to the United 
States pursuant to section 12(e) of the Act.
    Operator means the individual, partnership, firm, or corporation 
having control or management of operations on the lease or a portion 
thereof. The operator may be a lessee, designated agent of the lessee, 
or holder of rights under an approved operating agreement.
    Outer Continental Shelf means all submerged lands lying seaward and 
outside of the area of lands beneath navigable waters as defined in 
section 2 of Submerged Lands Act (43 U.S.C. 1301) and of which the 
subsoil and seabed appertain to the United States and are subject to 
its jurisdiction and control.
    Person means a citizen or national of the United States; an alien 
lawfully admitted for permanent residency in the United States as 
defined in 8 U.S.C. 1101(a)(20); a private, public, or municipal 
corporation organized under the laws of the United States or of any 
State or territory thereof; an association of such citizens, nationals, 
resident aliens or private, public, or municipal corporations, States, 
or political subdivisions of States; or anyone operating in a manner 
provided for by treaty or other applicable international agreements. 
The term does not include Federal Agencies.
    Secretary means the Secretary of the Interior or an official 
authorized to act on the Secretary's behalf.
    Testing means removing bulk samples for processing tests and 
feasibility studies and/or the testing of mining equipment to obtain 
information needed to develop a detailed Mining Plan.

Sec.  582.4  Opportunities for review and comment.

    (a) In carrying out BOEM's responsibilities under the Act and 
regulations in this part, the Director shall provide opportunities for 
Governors of adjacent States, State/Federal task forces, lessees and 
operators, other Federal Agencies, and other interested parties to 
review proposed activities described in a Delineation, Testing, or 
Mining Plan together with an analysis of potential impacts on the 
environment and to provide comments and recommendations for the 
disposition of the proposed plan.
    (b)(1) For Delineation Plans, the adjacent State Governor(s) shall 
be notified by the Director within 15 days following the submission of 
a request for approval of a Delineation Plan. Notification shall 
include a copy of the proposed Delineation Plan and the accompanying 
environmental information. The adjacent State Governor(s) who wishes to 
comment on a proposed Delineation Plan may do so within 30 days of the 
receipt of the proposed plan and the accompanying information.
    (2) In cases where an Environmental Assessment is to be prepared, 
the Director's invitation to provide comments may allow the adjacent 
State Governor(s) more than 30 days following receipt of the proposed 
plan to provide comments.
    (3) The Director shall notify Federal Agencies, as appropriate, 
with a copy of the proposed Delineation Plan and the accompanying 
environmental information within 15 days following the submission of 
the request. Agencies that wish to comment on a proposed Delineation 
Plan shall do so within 30 days following receipt of the plan and the 
accompanying information.
    (c)(1) For Testing Plans, the adjacent State Governor(s) shall be 
notified by the Director within 20 days following submission of a 
request for approval of a proposed Testing Plan. Notification shall 
include a copy of the proposed Testing Plan and the accompanying 
environmental information. The adjacent State Governor(s) who wishes to 
comment on a proposed Testing Plan may do so within 60 days of the 
receipt of a plan and the accompanying information.
    (2) In cases where an EIS is to be prepared, the Director's 
invitation to provide comments may allow the adjacent State Governor(s) 
more than 60 days following receipt of the proposed plan to provide 
comments.
    (3) The Director shall notify Federal Agencies, as appropriate, 
with a copy of the proposed Testing Plan and the accompanying 
environmental information within 20 days following the submission of 
the request. Agencies that wish to comment on a proposed Testing Plan 
shall do so within 60 days following receipt of the plan and the 
accompanying information.
    (d)(1) For Mining Plans, the adjacent State Governor(s) shall be 
notified by the Director within 20 days following the submission of a 
request for approval of a proposed Mining Plan. Notification shall 
include a copy of the proposed Mining Plan and the accompanying 
environmental information. The adjacent State Governor(s) who wishes to 
comment on a proposed Mining Plan may do so within 60 days of the 
receipt of a plan and the accompanying information.
    (2) In cases where an EIS is to be prepared, the Director's 
invitation to provide comments may allow the adjacent State Governor(s) 
more than 60 days following receipt of the proposed plan to provide 
comments.
    (3) The Director shall notify Federal Agencies, as appropriate, 
with a copy of

[[Page 64720]]

the proposed Mining Plan and the accompanying environmental information 
within 20 days following the submission of the request. Agencies that 
wish to comment on a proposed Mining Plan shall do so within 60 days 
following receipt of the plan and the accompanying information.
    (e) When an adjacent State Governor(s) has provided comments 
pursuant to paragraphs (b), (c), and (d) of this section, the 
Governor(s) shall be given, in writing, a list of recommendations which 
are adopted and the reasons for rejecting any of the recommendations of 
the Governor(s) or for implementing any alternative means identified 
during consultations with the Governor(s).

Sec.  582.5  Disclosure of data and information to the public.

    (a) The Director shall make data, information, and samples 
available in accordance with the requirements and subject to the 
limitations of the Act, the Freedom of Information Act (5 U.S.C. 552), 
and the implementing regulations (43 CFR part 2).
    (b) Geophysical data, processed G&G information, interpreted G&G 
information, and other data and information submitted pursuant to the 
requirements of this part shall not be available for public inspection 
without the consent of the lessee so long as the lease remains in 
effect, unless the Director determines that earlier limited release of 
such information is necessary for the unitization of operations on two 
or more leases, to ensure proper Mining Plans for a common orebody, or 
to promote operational safety. When the Director determines that early 
limited release of data and information is necessary, the data and 
information shall be shown only to persons with a direct interest in 
the affected lease(s), unitization agreement, or joint Mining Plan.
    (c) Geophysical data, processed geophysical information, and 
interpreted geophysical information collected on a lease with high 
resolution systems (including, but not limited to, bathymetry, side-
scan sonar, subbottom profiler, and magnetometer) in compliance with 
stipulations or orders concerning protection of environmental aspects 
of the lease may be made available to the public 60 days after 
submittal to the Director, unless the lessee can demonstrate to the 
satisfaction of the Director that release of the information or data 
would unduly damage the lessee's competitive position.

Sec.  582.6  Disclosure of data and information to an adjacent State.

    (a) Proprietary data, information, and samples submitted to BOEM 
pursuant to the requirements of this part shall be made available for 
inspection by representatives of adjacent State(s) upon request by the 
Governor(s) in accordance with paragraphs (b), (c), and (d) of this 
section.
    (b) Disclosure shall occur only after the Governor has entered into 
an agreement with the Secretary providing that:
    (1) The confidentiality of the information shall be maintained;
    (2) In any action commenced against the Federal Government or the 
State for failure to protect the confidentiality of proprietary 
information, the Federal Government or the State, as the case may be, 
may not raise as a defense any claim of sovereign immunity or any claim 
that the employee who revealed the proprietary information, which is 
the basis of the suit, was acting outside the scope of the person's 
employment in revealing the information;
    (3) The State agrees to hold the United States harmless for any 
violation by the State or its employees or contractors of the agreement 
to protect the confidentiality of proprietary data, information, and 
samples; and
    (c) The data, information, and samples available for inspection by 
representatives of adjacent State(s) pursuant to an agreement shall be 
related to leased lands.

Sec.  582.7  Jurisdictional controversies.

    In the event of a controversy between the United States and a State 
as to whether certain lands are subject to Federal or State 
jurisdiction, either the Governor of the State or the Secretary may 
initiate negotiations in an attempt to settle the jurisdictional 
controversy. With the concurrence of the Attorney General, the 
Secretary may enter into an agreement with a State with respect to OCS 
mineral activities and to payment and impounding of rents, royalties, 
and other sums and with respect to the issuance or nonissuance of new 
leases pending settlement of the controversy.

Subpart B--Jurisdiction and Responsibilities of Director

Sec.  582.10  Jurisdiction and responsibilities of Director.

    Subject to the authority of the Secretary, the following activities 
are subject to the regulations in this part and are under the 
jurisdiction of the Director: Exploration, testing, and mining 
operations together with the associated environmental protection 
measures needed to permit those activities to be conducted in an 
environmentally responsible manner; handling, measurement, and 
transportation of OCS minerals; and other operations and activities 
conducted pursuant to a lease issued under 30 CFR part 581, or pursuant 
to a right of use and easement granted under this part, by or on behalf 
of a lessee or the holder of a right of use and easement.

Sec.  582.11  Director's authority.

    (a) In the exercise of jurisdiction under Sec.  582.10, the 
Director is authorized and directed to act upon the requests, 
applications, and notices submitted under the regulations in this part; 
to issue either written or oral orders to govern lease operations; and 
to require compliance with applicable laws, regulations, and lease 
terms so that all operations conform to sound conservation practices 
and are conducted in a manner which is consistent with the following:
    (1) Make such OCS minerals available to meet the nation's needs in 
a timely manner;
    (2) Balance OCS mineral resource development with protection of the 
human, marine, and coastal environments;
    (3) Ensure the public a fair and equitable return on OCS minerals 
leased on the OCS; and
    (4) Foster and encourage private enterprise.
    (b)(1) The Director is to be provided ready access to all OCS 
mineral resource data and all environmental data acquired by the lessee 
or holder of a right of use and easement in the course of operations on 
a lease or right of use and easement and may require a lessee or holder 
to obtain additional environmental data when deemed necessary to assure 
adequate protection of the human, marine, and coastal environments.
    (2) The Director is to be provided an opportunity to inspect, cut, 
and remove representative portions of all samples acquired by a lessee 
in the course of operations on the lease.
    (c) In addition to the rights and privileges granted to a lessee 
under any lease issued or maintained under the Act, on request, the 
Director may grant a lessee, subject to such conditions as the Director 
may prescribe, a right of use and easement to construct and maintain 
platforms, artificial islands, and/or other installations and devices 
which are permanently or temporarily attached to the seabed and which 
are needed for the conduct of leasehold exploration, testing, 
development, production, and

[[Page 64721]]

processing activities or other leasehold related operations whether on 
or off the lease.
    (d)(1) The Director may approve the consolidation of two or more 
OCS mineral leases or portions of two or more OCS mineral leases into a 
single mining unit requested by lessees, or the Director may require 
such consolidation when the operation of those leases or portions of 
leases as a single mining unit is in the interest of conservation of 
the natural resources of the OCS or the prevention of waste. A mining 
unit may also include all or portions of one or more OCS mineral leases 
with all or portions of one or more adjacent State leases for minerals 
in a common orebody. A single unit operator shall be responsible for 
submission of required Delineation, Testing, and Mining Plans covering 
OCS mineral operations for an approved mining unit.
    (2) Operations such as exploration, testing, and mining activities 
conducted in accordance with an approved plan on any lease or portion 
of a lease which is subject to an approved mining unit shall be 
considered operations on each of the leases that is made subject to the 
approved mining unit.
    (3) Minimum royalty paid pursuant to a Federal lease, which is 
subject to an approved mining unit, is creditable against the 
production royalties allocated to that Federal lease during the lease 
year for which the minimum royalty is paid.
    (4) Any OCS minerals produced from State and Federal leases which 
are subject to an approved mining unit shall be accounted for 
separately unless a method of allocating production between State and 
Federal leases has been approved by the Director and the appropriate 
State official.

Sec.  582.12  Director's responsibilities.

    (a) The Director is responsible for the regulation of activities to 
assure that all operations conducted under a lease or right of use and 
easement are conducted in a manner that protects the environment and 
promotes orderly development of OCS mineral resources. Those activities 
are to be designed to prevent serious harm or damage to, or waste of, 
any natural resource (including OCS mineral deposits and oil, gas, and 
sulphur resources in areas leased or not leased), any life (including 
fish and other aquatic life), property, or the marine, coastal, or 
human environment.
    (b)(1) In the evaluation of a Delineation Plan, the Director shall 
consider whether the plan is consistent with:
    (i) The provisions of the lease;
    (ii) The provisions of the Act;
    (iii) The provisions of the regulations prescribed under the Act;
    (iv) Other applicable Federal law; and
    (v) Requirements for the protection of the environment, health, and 
safety.
    (2) Within 30 days following the completion of an environmental 
assessment or other NEPA document prepared pursuant to the regulations 
implementing NEPA or within 30 days following the comment period 
provided in Sec.  582.4(b) of this part, the Director shall:
    (i) Approve any Delineation Plan which is consistent with the 
criteria in paragraph (b)(1) of this section;
    (ii) Require the lessee to modify any Delineation Plan that is 
inconsistent with the criteria in paragraph (b)(1) of this section; or
    (iii) Disapprove a Delineation Plan when it is determined that an 
activity proposed in the plan would probably cause serious harm or 
damage to life (including fish and other aquatic life); to property; to 
natural resources of the OCS including mineral deposits (in areas 
leased or not leased); or to the marine, coastal, or human environment, 
and the proposed activity cannot be modified to avoid the conditions.
    (3) The Director shall notify the lessee in writing of the reasons 
for disapproving a Delineation Plan or for requiring modification of a 
plan and the conditions that must be met for plan approval.
    (c)(1) In the evaluation of a Testing Plan, the Director shall 
consider whether the plan is consistent with:
    (i) The provisions of the lease;
    (ii) The provisions of the Act;
    (iii) The provisions of the regulations prescribed under the Act;
    (iv) Other applicable Federal law;
    (v) Environmental, safety, and health requirements; and
    (vi) The statutory requirement to protect property, natural 
resources of the OCS, including mineral deposits (in areas leased or 
not leased), and the National security or defense.
    (2) Within 60 days following the release of a final EIS prepared 
pursuant to NEPA or within 60 days following the comment period 
provided in Sec.  582.4(c) of this part, the Director shall:
    (i) Approve any Testing Plan which is consistent with the criteria 
in paragraph (c)(1) of this section;
    (ii) Require the lessee to modify any Testing Plan which is 
inconsistent with the criteria in paragraph (c)(1) of this section; or
    (iii) Disapprove any Testing Plan when the Director determines the 
existence of exceptional geological conditions in the lease area, 
exceptional resource values in the marine or coastal environment, or 
other exceptional circumstances and that (A) implementation of the 
activities described in the plan would probably cause serious harm and 
damage to life (including fish and other aquatic life), to property, to 
any mineral deposit (in areas leased or not leased), to the National 
security or defense, or to the marine, coastal, or human environments; 
(B) that the threat of harm or damage will not disappear or decrease to 
an acceptable extent within a reasonable period of time; and (C) the 
advantages of disapproving the Testing Plan outweigh the advantages of 
development and production of the OCS mineral resources.
    (3) The Director shall notify the lessee in writing of the 
reason(s) for disapproving a Testing Plan or for requiring modification 
of a Testing Plan and the conditions that must be met for approval of 
the plan.
    (d)(1) In the evaluation of a Mining Plan, the Director shall 
consider whether the plan is consistent with:
    (i) The provisions of the lease;
    (ii) The provisions of the Act;
    (iii) The provisions of the regulations prescribed under the Act;
    (iv) Other applicable Federal law;
    (v) Environmental, safety, and health requirements; and
    (vi) The statutory requirements to protect property, natural 
resources of the OCS, including mineral deposits (in areas leased or 
not leased), and the National security or defense.
    (2) Within 60 days following the release of a final EIS prepared 
pursuant to NEPA or within 60 days following the comment period 
provided in Sec.  582.4(d) of this part, the Director shall:
    (i) Approve any Mining Plan which is consistent with the criteria 
in paragraph (d)(1) of this section;
    (ii) Require the lessee to modify any Mining Plan which is 
inconsistent with the criteria in paragraph (d)(1) of this section; or
    (iii) Disapprove any Mining Plan when the Director determines the 
existence of exceptional geological conditions in the lease area, 
exceptional resource values in the marine or coastal environment, or 
other exceptional circumstances, and that:
    (A) Implementation of the activities described in the plan would 
probably cause serious harm and damage to life (including fish and 
other aquatic life), to property, to any mineral deposit (in areas 
leased or not leased), to the National security or defense, or to the 
marine, coastal, or human environments;

[[Page 64722]]

    (B) That the threat of harm or damage will not disappear or 
decrease to an acceptable extent within a reasonable period of time; 
and
    (C) The advantages of disapproving the Mining Plan outweigh the 
advantages of development and production of the OCS mineral resources.
    (3) The Director shall notify the lessee in writing of the 
reason(s) for disapproving a Mining Plan or for requiring modification 
of a Mining Plan and the conditions that must be met for approval of 
the plan.
    (e)-(f) [Reserved]
    (g) The Director shall establish practices and procedures to govern 
the collection of all rents, royalties, and other payments due the 
Federal Government in accordance with terms of the leasing notice, the 
lease, and the applicable Royalty Management regulations listed in 
Sec.  581.26(i) of this chapter.
    (h) [Reserved]

Sec.  582.13  [Reserved]

Sec.  582.14  Noncompliance, remedies, and penalties.

    (a)(1) If the Director determines that a lessee has failed to 
comply with applicable provisions of law; the regulations in this part; 
other applicable regulations; the lease; the approved Delineation, 
Testing, or Mining Plan; or the Director's orders or instructions, and 
the Director determines that such noncompliance poses a threat of 
immediate, serious, or irreparable damage to the environment, the mine 
or the deposit being mined, or other valuable mineral deposits or other 
resources, the Director shall order the lessee to take immediate and 
appropriate remedial action to alleviate the threat. Any oral orders 
shall be followed up by service of a notice of noncompliance upon the 
lessee by delivery in person to the lessee or agent, or by certified or 
registered mail addressed to the lessee at the last known address.
    (2) If the Director determines that the lessee has failed to comply 
with applicable provisions of law; the regulations in this part; other 
applicable regulations; the lease; the requirements of an approved 
Delineation, Testing, or Mining Plan; or the Director's orders or 
instructions, and such noncompliance does not pose a threat of 
immediate, serious, or irreparable damage to the environment, the mine 
or the deposit being mined, or other valuable mineral deposits or other 
resources, the Director shall serve a notice of noncompliance upon the 
lessee by delivery in person to the lessee or agent or by certified or 
registered mail addressed to the lessee at the last known address.
    (b) A notice of noncompliance shall specify in what respect(s) the 
lessee has failed to comply with the provisions of applicable law; 
regulations; the lease; the requirements of an approved Delineation, 
Testing, or Mining Plan; or the Director's orders or instructions, and 
shall specify the action(s) which must be taken to correct the 
noncompliance and the time limits within which such action must be 
taken.
    (c) Failure of a lessee to take the actions specified in the notice 
of noncompliance within the time limit specified shall be grounds for a 
suspension of operations and other appropriate actions, including but 
not limited to the assessment of a civil penalty of up to $10,000 per 
day for each violation that is not corrected within the time period 
specified (43 U.S.C. 1350(b)).
    (d) Whenever the Director determines that a violation of or failure 
to comply with any provision of the Act; or any provision of a lease, 
license, or permit issued pursuant to the Act; or any provision of any 
regulation promulgated under the Act probably occurred and that such 
apparent violation continued beyond notice of the violation and the 
expiration of the reasonable time period allowed for corrective action, 
the Director shall follow the procedures concerning remedies and 
penalties in subpart N, Remedies and Penalties, of 30 CFR part 550 to 
determine and assess an appropriate penalty.
    (e) The remedies and penalties prescribed in this section shall be 
concurrent and cumulative, and the exercise of one shall not preclude 
the exercise of the other. Further, the remedies and penalties 
prescribed in this section shall be in addition to any other remedies 
and penalties afforded by any other law or regulation (43 U.S.C. 
1350(e)).

Sec.  582.15  Cancellation of leases.

    (a) Whenever the owner of a nonproducing lease fails to comply with 
any of the provisions of the Act, the lease, or the regulations issued 
under the Act, and the default continues for a period of 30 days after 
mailing of notice by registered or certified letter to the lease owner 
at the owner's record post office address, the Secretary may cancel the 
lease pursuant to section 5(c) of the Act, and the lessee shall not be 
entitled to compensation. Any such cancellation is subject to judicial 
review as provided by section 23(b) of the Act.
    (b) Whenever the owner of any producing lease fails to comply with 
any of the provisions of the Act, the lease, or the regulations issued 
under the Act, the Secretary may cancel the lease only after judicial 
proceedings pursuant to section 5(d) of the Act, and the lessee shall 
not be entitled to compensation.
    (c) Any lease issued under the Act, whether producing or not, may 
be canceled by the Secretary upon proof that it was obtained by fraud 
or misrepresentation and after notice and opportunity to be heard has 
been afforded to the lessee.
    (d) The Secretary may cancel a lease in accordance with the 
following:
    (1) Cancellation may occur at any time if the Secretary determines 
after a hearing that:
    (i) Continued activity pursuant to such lease would probably cause 
serious harm or damage to life (including fish and other aquatic life), 
to property, to any mineral (in areas leased or not leased), to the 
National security or defense, or to the marine, coastal, or human 
environment;
    (ii) The threat of harm or damage will not disappear or decrease to 
an acceptable extent within a reasonable period of time; and
    (iii) The advantages of cancellation outweigh the advantages of 
continuing such lease in force.
    (2) Cancellation shall not occur unless and until operations under 
such lease shall have been under suspension or temporary prohibition by 
the Secretary, with due extension of any lease term continuously for a 
period of 5 years or for a lesser period upon request of the lessee;
    (3) Cancellation shall entitle the lessee to receive such 
compensation as is shown to the Secretary as being equal to the lesser 
of:
    (i) The fair value of the canceled rights as of the date of 
cancellation, taking account of both anticipated revenues from the 
lease and anticipated costs, including costs of compliance with all 
applicable regulations and operating orders, liability for cleanup 
costs or damages, or both, and all other costs reasonably anticipated 
on the lease, or
    (ii) The excess, if any, over the lessee's revenue from the lease 
(plus interest thereon from the date of receipt to date of 
reimbursement) of all consideration paid for the lease and all direct 
expenditures made by the lessee after the date of issuance of such 
lease and in connection with exploration or development, or both, 
pursuant to the lease (plus interest on such consideration and such 
expenditures from date of payment to date of reimbursement), except 
that in the case

[[Page 64723]]

of joint leases which are canceled due to the failure of one or more 
partners to exercise due diligence, the innocent parties shall have the 
right to seek damages for such loss from the responsible party or 
parties and the right to acquire the interests of the negligent party 
or parties and be issued the lease in question.
    (iii) The lessee shall not be entitled to compensation where one of 
the following circumstances exists when a lease is canceled:
    (A) A producing lease is forfeited or is canceled pursuant to 
section (5)(d) of the Act;
    (B) A Testing Plan or Mining Plan is disapproved because the 
lessee's failure to demonstrate compliance with the requirements of 
applicable Federal law; or
    (C) The lessee of a nonproducing lease fails to comply with a 
provision of the Act, the lease, or regulations issued under the Act, 
and the noncompliance continues for a period of 30 days or more after 
the mailing of a notice of noncompliance by registered or certified 
letter to the lessee.

Subpart C--Obligations and Responsibilities of Lessees

Sec.  582.20  Obligations and responsibilities of lessees.

    (a) The lessee shall comply with the provisions of applicable laws; 
regulations; the lease; the requirements of the approved Delineation, 
Testing, or Mining Plans; and other written or oral orders or 
instructions issued by the Director when performing exploration, 
testing, development, and production activities pursuant to a lease 
issued under 30 CFR part 581. The lessee shall take all necessary 
precautions to prevent waste and damage to oil, gas, sulphur, and other 
OCS mineral-bearing formations and shall conduct operations in such 
manner that does not cause or threaten to cause harm or damage to life 
(including fish and other aquatic life); to property; to the National 
security or defense; or to the marine, coastal, or human environment 
(including onshore air quality). The lessee shall make all mineral 
resource data and information and all environmental data and 
information acquired by the lessee in the course of exploration, 
testing, development, and production operations on the lease available 
to the Director for examination and copying at the lease site or an 
onshore location convenient to the Director.
    (b) In all cases where there is more than one lease owner of 
record, one person shall be designated payor for the lease. The payor 
shall be responsible for making all rental, minimum royalty, and 
royalty payments.
    (c) In all cases where lease operations are not conducted by the 
sole lessee, a ``designation of operator'' shall be submitted to and 
accepted by the Director prior to the commencement of leasehold 
operations. This designation when accepted will be recognized as 
authority for the designee to act on behalf of the lessees and to 
fulfill the lessees' obligations under the Act, the lease, and the 
regulations of this part. All changes of address and any termination of 
a designation of operator shall be reported immediately, in writing, to 
the Director. In the case of a termination of a designation of operator 
or in the event of a controversy between the lessee and the designated 
operator, both the lessee and the designated operator will be 
responsible for the protection of the interests of the lessor.
    (d) When required by the Director or at the option of the lessee, 
the lessee shall submit to the Director the designation of a local 
representative empowered to receive notices, provide access to OCS 
mineral and environmental data and information, and comply with orders 
issued pursuant to the regulations of this part. If there is a change 
in the designated representative, the Director shall be notified 
immediately.
    (e) Before beginning operations, the lessee shall inform the 
Director in writing of any designation of a local representative under 
paragraph (d) of this section and the address of the mine office 
responsible for the exploration, testing, development, or production 
activities; the lessee's temporary and permanent addresses; or the name 
and address of the designated operator who will be responsible for the 
operations, and who will act as the local representative of the lessee. 
The Director shall also be informed of each change thereafter in the 
address of the mine office or in the name or address of the local 
representative.
    (f) The holder of a right-of-use and easement shall exercise its 
rights under the right of use and easement in accordance with the 
regulations of this part.
    (g) A lessee shall submit reports and maintain records in 
accordance with Sec.  582.29 of this part.
    (h) When an oral approval is given by BOEM in response to an oral 
request under these regulations, the oral request shall be confirmed in 
writing by the lessee or holder of a right of use and easement within 
72 hours.
    (i) The lessee is responsible for obtaining all permits and 
approvals from BOEM, BSEE or other Agencies needed to carry out 
exploration, testing, development, and production activities under a 
lease issued under 30 CFR part 581 of this title.

Sec.  582.21  Plans, general.

    (a) No exploration, testing, development, or production activities, 
except preliminary activities, shall be commenced or conducted on any 
lease except in accordance with a plan submitted by the lessee and 
approved by the Director. Plans will not be approved before completion 
of comprehensive technical and environmental evaluations to assure that 
the activities described will be carried out in a safe and 
environmentally responsible manner. Prior to the approval of a plan, 
the Director will assure that the lessee is prepared to take adequate 
measures to prevent waste; conserve natural resources of the OCS; and 
protect the environment, human life, and correlative rights. The lessee 
shall demonstrate to the satisfaction of the Director that the lease is 
in good standing, the lessee is authorized and capable of conducting 
the activities described in the plan, and that an acceptable bond has 
been provided.
    (b) Plans shall be submitted to the Director for approval. The 
lessee shall submit the number of copies prescribed by the Director. 
Such plans shall describe in detail the activities that are to be 
conducted and shall demonstrate that the proposed exploration, testing, 
development, and production activities will be conducted in an 
operationally safe and environmentally responsible manner that is 
consistent with the provisions of the lease, applicable laws, and 
regulations. The Governor of an affected State and other Federal 
Agencies shall be provided an opportunity to review and provide 
comments on proposed Delineation, Testing, and Mining Plans and any 
proposal for a significant modification to an approved plan. Following 
review, including the technical and environmental evaluations, the 
Director shall either approve, disapprove, or require the lessee to 
modify its proposed plan.
    (c) Lessees are not required to submit a Delineation or Testing 
Plan prior to submittal of a proposed Testing or Mining Plan if the 
lessee has sufficient data and information on which to base a Testing 
or Mining Plan without carrying out postlease exploration and/or 
testing activities. A Mining Plan may include proposed exploration or 
testing activities where those activities are needed to obtain 
additional data and information on which to base plans for future 
mining activities. A Testing Plan

[[Page 64724]]

may include exploration activities when those activities are needed to 
obtain additional data or information on which to base plans for future 
testing or mining activities.
    (d) Preliminary activities are bathymetric, geological, 
geophysical, mapping, and other surveys necessary to develop a 
comprehensive Delineation, Testing, or Mining Plan. Such activities are 
those which have no significant adverse impact on the natural resources 
of the OCS. The lessee shall give notice to the Director at least 30 
days prior to initiating the proposed preliminary activities on the 
lease. The notice shall describe in detail those activities that are to 
be conducted and the time schedule for conducting those activities.
    (e) Leasehold activities shall be carried out with due regard to 
conservation of resources, paying particular attention to the wise 
management of OCS mineral resources, minimizing waste of the leased 
resource(s) in mining and processing, and preventing damage to unmined 
parts of the mineral deposit and other resources of the OCS.

Sec.  582.22  Delineation Plan.

    All exploration activities shall be conducted in accordance with a 
Delineation Plan submitted by the lessee and approved by the Director. 
The Delineation Plan shall describe the proposed activities necessary 
to locate leased OCS minerals, characterize the quantity and quality of 
the minerals, and generate other information needed for the development 
of a comprehensive Testing or Mining Plan. A Delineation Plan at a 
minimum shall include the following:
    (a) The OCS mineral(s) or primary interest.
    (b) A brief narrative description of the activities to be conducted 
and how the activities will lead to the discovery and evaluation of a 
commercially minable deposit on the lease.
    (c) The name, registration, and type of equipment to be used, 
including vessel types as well as their navigation and mobile 
communication systems, and transportation corridors to be used between 
the lease and shore.
    (d) Information showing that the equipment to be used (including 
the vessel) is capable of performing the intended operation in the 
environment which will be encountered.
    (e) Maps showing the proposed locations of test drill holes, the 
anticipated depth of penetration of test drill holes, the locations 
where surficial samples were taken, and the location of proposed 
geophysical survey lines for each surveying method being employed.
    (f) A description of measures to be taken to avoid, minimize, or 
otherwise mitigate air, land, and water pollution and damage to aquatic 
and wildlife species and their habitats; any unique or special features 
in the lease area; aquifers; other natural resources of the OCS; and 
hazards to public health, safety, and navigation.
    (g) A schedule indicating the starting and completion dates for 
each proposed exploration activity.
    (h) A list of any known archaeological resources on the lease and 
measures to assure that the proposed exploration activities do not 
damage those resources.
    (i) A description of any potential conflicts with other uses and 
users of the area.
    (j) A description of measures to be taken to monitor the effects of 
the proposed exploration activities on the environment in accordance 
with Sec.  582.28(c) of this part.
    (k) A detailed description of practices and procedures to effect 
the abandonment of exploration activities, e.g., plugging of test drill 
holes. The proposed procedures shall indicate the steps to be taken to 
assure that test drill holes and other testing procedures which 
penetrate the seafloor to a significant depth are properly sealed and 
that the seafloor is left free of obstructions or structures that may 
present a hazard to other uses or users of the OCS such as navigation 
or commercial fishing.
    (l) A detailed description of the cycle of all materials, the 
method for discharge and disposal of waste and refuse, and the chemical 
and physical characteristics of waste and refuse.
    (m) A description of the potential environmental impacts of the 
proposed exploration activities including the following:
    (1) The location of associated port, transport, processing, and 
waste disposal facilities and affected environment (e.g., maps, land 
use, and layout);
    (2) A description of the nature and degree of environmental impacts 
and the domestic socioeconomic effects of construction and operation of 
the associated facilities, including waste characteristics and 
toxicity;
    (3) Any proposed mitigation measures to avoid or minimize adverse 
impacts on the environment;
    (4) A certificate of consistency with the federally approved State 
coastal zone management program, where applicable; and
    (5) Alternative sites and technologies considered by the lessee and 
the reasons why they were not chosen.
    (n) Any other information needed for technical evaluation of the 
planned activity, such as sample analyses to be conducted at sea, and 
the evaluation of potential environmental impacts.

Sec.  582.23  Testing Plan.

    All testing activities shall be conducted in accordance with a 
Testing Plan submitted by the lessee and approved by the Director. 
Where a lessee needs more information to develop a detailed Mining Plan 
than is obtainable under an approved Delineation Plan, to prepare 
feasibility studies, to carry out a pilot program to evaluate 
processing techniques or technology or mining equipment, or to 
determine environmental effects by a pilot test mining operation, the 
lessee shall submit a comprehensive Testing Plan for the Director's 
approval. Any OCS minerals acquired during activities conducted under 
an approved Testing Plan will be subject to the payment of royalty 
pursuant to the governing lease terms. A Testing Plan at a minimum 
shall include the following:
    (a) The nature and purpose of the proposed testing program.
    (b) A comprehensive description of the activities to be performed 
including descriptions of the proposed methods for analysis of samples 
taken.
    (c) A narrative description and maps showing water depths and the 
locations of the proposed pilot mining or other testing activities.
    (d) A comprehensive description of the method and manner in which 
testing activities will be conducted and the results the lessee expects 
to obtain as a result of those activities.
    (e) The name, registration, and type of equipment to be used, 
including vessel types together with their navigation and mobile 
communication systems, and transportation corridors to be used between 
the lease and shore.
    (f) Information showing that the equipment to be used (including 
the vessel) is capable of performing the intended operation in the 
environment which will be encountered.
    (g) A schedule specifying the starting and completion dates for 
each of the testing activities.
    (h) A list of known archaeological resources on the lease and 
measures to be used to assure that the proposed testing activities do 
not damage those resources.
    (i) A description of any potential conflicts with other uses and 
users of the area.
    (j) A description of measures to be taken to avoid, minimize, or 
otherwise mitigate air, land, and water pollution and damage to aquatic 
and wildlife

[[Page 64725]]

species and their habitat; any unique or special features in the lease 
area, other natural resources of the OCS; and hazards to public health, 
safety, and navigation.
    (k) A description of the measures to be taken to monitor the 
impacts of the proposed testing activities in accordance with Sec.  
582.28(c) of this part.
    (l) A detailed description of the cycle of all materials including 
samples and wastes, the method for discharge and disposal of waste and 
refuse, and the chemical and physical characteristics of such waste and 
refuse.
    (m) A detailed description of practices and procedures to effect 
the abandonment of testing activities, e.g., abandonment of a pilot 
mining facility. The proposed procedures shall indicate the steps to be 
taken to assure that mined areas do not pose a threat to the 
environment and that the seafloor is left free of obstructions and 
structures that may present a hazard to other uses or users of the OCS 
such as navigation or commercial fishing.
    (n) A description of potential environmental impacts of testing 
activities including the following:
    (1) The location of associated port, transport, processing, and 
waste disposal facilities and affected environment (e.g., maps, land 
use, and layout);
    (2) A description of the nature and degree of potential 
environmental impacts of the proposed testing activities and the 
domestic socioeconomic effects of construction and operation of the 
proposed testing facilities, including waste characteristics and 
toxicity;
    (3) Any proposed mitigation measures to avoid or minimize adverse 
impacts on the environment;
    (4) A certificate of consistency with the federally approved State 
coastal zone management program, where applicable; and
    (5) Alternate sites and technologies considered by the lessee and 
the reasons why they were not selected.
    (o) Any other information needed for technical evaluation of the 
planned activities and for evaluation of the impact of those activities 
on the human, marine, and coastal environments.

Sec.  582.24  Mining Plan.

    All OCS mineral development and production activities shall be 
conducted in accordance with a Mining Plan submitted by the lessee and 
approved by the Director. A Mining Plan shall include comprehensive 
detailed descriptions, illustrations, and explanations of the proposed 
OCS mineral development, production, and processing activities and 
accurately present the lessee's proposed plan of operation. A Mining 
Plan at a minimum shall include the following:
    (a) A narrative description of the mining activities including:
    (1) The OCS mineral(s) or material(s) to be recovered;
    (2) Estimates of the number of tons and grade(s) of ore to be 
recovered;
    (3) Anticipated annual production;
    (4) Volume of ocean bottom expected to be disturbed (area and depth 
of disruption) each year; and
    (5) All activities of the mining cycle from extraction through 
processing and waste disposal.
    (b) Maps of the lease showing water depths, the outline of the 
mineral deposit(s) to be mined with cross sections showing thickness, 
and the area(s) anticipated to be mined each year.
    (c) The name, registration, and type of equipment to be used, 
including vessel types as well as their navigation and mobile 
communication systems, and transportation corridors to be used between 
the lease and shore.
    (d) Information showing that the equipment to be used (including 
the vessel) is capable of performing the intended operation in the 
environment which will be encountered.
    (e) A description of equipment to be used in mining, processing, 
and transporting of the ore.
    (f) A schedule indicating the anticipated starting and completion 
dates for each activity described in the plan.
    (g) For onshore processing, a description of how OCS minerals are 
to be processed and how the produced OCS minerals will be weighed, 
assayed, and royalty determinations made.
    (h) For at-sea processing, additional information including type 
and size of installation or structures and the method of tailings 
disposal.
    (i) A list of known archaeological resources on the lease and the 
measures to be taken to assure that the proposed mining activities do 
not damage those resources.
    (j) Description of any potential conflicts with other uses and 
users of the area.
    (k) A detailed description of the nature and occurrence of the OCS 
mineral deposit(s) in the leased area with adequate maps and sections.
    (l) A detailed description of development and mining methods to be 
used, the proposed sequence of mining or development, the expected 
production rate, the method and location of the proposed processing 
operation, and the method of measuring production.
    (m) A detailed description of the method of transporting the 
produced OCS minerals from the lease to shore and adequate maps showing 
the locations of pipelines, conveyors, and other transportation 
facilities and corridors.
    (n) A detailed description of the cycle of all materials including 
samples and wastes, the method of discharge and disposal of waste and 
refuse, and the chemical and physical characteristics of the waste and 
refuse.
    (o) A description of measures to be taken to avoid, minimize, or 
otherwise mitigate air, land, and water pollution and damage to aquatic 
and wildlife species and their habitats; any unique or special features 
in the lease area, aquifers, or other natural resources of the OCS; and 
hazards to public health, safety, and navigation.
    (p) A detailed description of measures to be taken to monitor the 
impacts of the proposed mining and processing activities on the 
environment in accordance with Sec.  582.28(c) of this part.
    (q) A detailed description of practices and procedures to effect 
the abandonment of mining and processing activities. The proposed 
procedures shall indicate the steps to be taken to assure that mined 
areas on tailing deposits do not pose a threat to the environment and 
that the seafloor is left free of obstructions and structures that 
present a hazard to other users or uses of the OCS such as navigation 
or commercial fishing.
    (r) A description of potential environmental impacts of mining 
activities including the following:
    (1) The location of associated port, transport, processing, and 
waste disposal facilities and the affected environment (e.g., maps, 
land use, and layout);
    (2) A description of the nature and degree of potential 
environmental impacts of the proposed mining activities and the 
domestic socioeconomic effects of construction and operation of the 
associated facilities, including waste characteristics and toxicity;
    (3) Any proposed mitigation measures to avoid or minimize adverse 
impacts on the environment;
    (4) A certificate of consistency with the federally approved State 
coastal zone management program, where applicable; and
    (5) Alternative sites and technologies considered by the lessee and 
the reasons why they were not chosen.
    (s) Any other information needed for technical evaluation of the 
proposed activities and for the evaluation of potential impacts on the 
environment.

[[Page 64726]]

Sec.  582.25  Plan modification.

    Approved Delineation, Testing, and Mining Plans may be modified 
upon the Director's approval of the changes proposed. When 
circumstances warrant, the Director may direct the lessee to modify an 
approved plan to adjust to changed conditions. If the lessee requests 
the change, the lessee shall submit a detailed, written statement of 
the proposed modifications, potential impacts, and the justification 
for the proposed changes. Revision of an approved plan whether 
initiated by the lessee or ordered by the Director shall be submitted 
to the Director for approval. When the Director determines that a 
proposed revision could result in significant change in the impacts 
previously identified and evaluated or requires additional permits, the 
proposed plan revision shall be subject to the applicable review and 
approval procedures of Sec. Sec.  582.21, 582.22, 582.23, and 582.24 of 
this part.

Sec.  582.26  Contingency Plan.

    (a) When required by the Director, a lessee shall include a 
Contingency Plan as part of its request for approval of a Delineation, 
Testing, or Mining Plan. The Contingency Plan shall comply with the 
requirements of Sec.  582.28(e) of this part.
    (b) The Director may order or the lessee may request the Director's 
approval of a modification of the Contingency Plan when such a change 
is necessary to reflect any new information concerning the nature, 
magnitude, and significance of potential equipment or procedural 
failures or the effectiveness of the corrective actions described in 
the Contingency Plan.

Sec.  582.27  Conduct of operations.

    (a)-(h) [Reserved]
    (i) Any bulk sampling or testing that is necessary to be conducted 
prior to submission of a Mining Plan shall be in accordance with an 
approved Testing Plan. The sale of any OCS minerals acquired under an 
approved Testing Plan shall be subject to the payment of the royalty 
specified in the lease to the United States.
    (j)-(m) [Reserved]

Sec.  582.28  Environmental protection measures.

    (a) Exploration, testing, development, production, and processing 
activities proposed to be conducted under a lease will only be approved 
by the Director upon the determination that the adverse impacts of the 
proposed activities can be avoided, minimized, or otherwise mitigated. 
The Director shall take into account the information contained in the 
sale-specific environmental evaluation prepared in association with the 
lease offering as well as the site- and operational-specific 
environmental evaluations prepared in association with the review and 
evaluation of the approved Delineation, Testing, or Mining Plan. The 
Director's review of the air quality consequences of proposed OCS 
activities will follow the practices and procedures specified in 30 CFR 
250.194, Sec. Sec.  550.194, 550.218, 550.249, and 550.303.
    (b) If the baseline data available are judged by the Director to be 
inadequate to support an environmental evaluation of a proposed 
Delineation, Testing, or Mining Plan, the Director may require the 
lessee to collect additional environmental baseline data prior to the 
approval of the activities proposed.
    (c)(1) [Reserved];
    (2) Monitoring of environmental effects shall include determination 
of the spatial and temporal environmental changes induced by the 
exploration, testing, development, production, and processing 
activities on the flora and fauna of the sea surface, the water column, 
and/or the seafloor.
    (3) [Reserved];
    (4) [Reserved]
    (5) When prototype test mining is proposed, the lessee shall 
include a monitoring strategy for assessing the impacts of the testing 
activities and for developing a strategy for monitoring commercial-
scale recovery and mitigating the impacts of commercial-scale recovery 
more effectively. At a minimum, the proposed monitoring activities 
shall address specific concerns expressed in the lease-sale 
environmental analysis.
    (6) When required, the monitoring plan shall specify:
    (i) The sampling techniques and procedures to be used to acquire 
the needed data and information;
    (ii) The format to be used in analysis and presentation of the data 
and information;
    (iii) The equipment, techniques, and procedures to be used in 
carrying out the monitoring program; and
    (iv) The name and qualifications of person(s) designated to be 
responsible for carrying out the environmental monitoring.
    (d) [Reserved]
    (e) In the event that equipment or procedural failure might result 
in significant additional damage to the environment, the lessee shall 
submit a Contingency Plan which specifies the procedures to be followed 
to institute corrective actions in response to such a failure and to 
minimize adverse impacts on the environment. Such procedures shall be 
designed for the site and mining activities described in the approved 
Delineation, Testing, or Mining Plan.

Sec.  582.29  Reports and records.

    (a) A report of the amount and value of each OCS mineral produced 
from each lease shall be made by the payor for the lease for each 
calendar month, beginning with the month in which approved testing, 
development, or production activities are initiated and shall be filed 
in duplicate with the Director on or before the 20th day of the 
succeeding month, unless an extension of time for the filing of such 
report is granted by the Director. The report shall disclose accurately 
and in detail all operations conducted during each month and present a 
general summary of the status of leasehold activities. The report shall 
be submitted each month until the lease is terminated or relinquished 
unless the Director authorizes omission of the report during an 
approved suspension of production. The report shall show for each 
calendar month the location of each mining and processing activity; the 
number of days operations were conducted; the identity, quantity, 
quality, and value of each OCS mineral produced, sold, transferred, 
used or otherwise disposed of; identity, quantity, and quality of an 
inventory maintained prior to the point of royalty determination; and 
other information as may be required by the Director.
    (b) The lessee shall submit a status report on exploration and/or 
testing activities under an approved Delineation or Testing Plan to the 
Director within 30 days of the close of each calendar quarter which 
shall include:
    (1) A summary of activities conducted;
    (2) A listing of all geophysical and geochemical data acquired and 
developed such as acoustic or seismic profiling records;
    (3) A map showing location of holes drilled and where bottom 
samples were taken; and
    (4) Identification of samples analyzed.
    (c) Each lessee shall submit to the Director a report of 
exploration and/or testing activities within 3 months after the 
completion of operations. The final report of exploration and/or 
testing activities conducted on the lease shall include:
    (1) A description of work performed;
    (2) Charts, maps, or plats depicting the area and leases in which 
activities were conducted specifically identifying the lines of 
geophysical traverses and/or the locations where geological activity 
was conducted and/or the locations of other exploration and testing 
activities;

[[Page 64727]]

    (3) The dates on which the actual operations were performed;
    (4) A narrative summary of any mineral occurrences; environmental 
hazards; and effects of the activities on the environment, aquatic 
life, archaeological resources, or other uses and users of the area in 
which the activities were conducted;
    (5) Such other descriptions of the activities conducted as may be 
specified by the Director; and
    (6) Records of all samples from core drilling or other tests made 
on the lease. The records shall be in such form that the location and 
direction of the samples can be accurately located on a map. The 
records shall include logs of all strata penetrated and conditions 
encountered, such as minerals, water, gas, or unusual conditions, and 
copies of analyses of all samples analyzed.
    (d) The lessee shall report the results of environmental monitoring 
activities required in Sec.  582.28 of this part and shall submit such 
other environmental data as the Director may require to conform with 
the requirements of these regulations.
    (e)(1) All maps shall be appropriately marked with reference to 
official lease boundaries and elevations marked with reference to sea 
level. When required by the Director, vertical projections and cross 
sections shall accompany plan views. The maps shall be kept current and 
submitted to the Director annually, or more often when required by the 
Director. The accuracy of maps furnished shall be certified by a 
professional engineer or land surveyor.
    (2) The lessee shall prepare such maps of the leased lands as are 
necessary to show the geological conditions as determined from G&G 
surveys, bottom sampling, drill holes, trenching, dredging, or mining. 
All excavations shall be shown in such manner that the volume of OCS 
minerals produced during a royalty period can be accurately 
ascertained.
    (f) Any lessee who acquires rock, mineral, and core samples under a 
lease shall keep a representative split of each geological sample and a 
quarter longitudinal segment of each core for 5 years during which time 
the samples shall be available for inspection at the convenience of the 
Director who may take cuts of such cores, cuttings, and samples.
    (g)(1) The lessee shall keep all original data and information 
available for inspection or duplication, by the Director at the expense 
of the lessor, as long as the lease continues in force. Should the 
lessee choose to dispose of original data and information once the 
lease has expired, said data and information shall be offered to the 
lessor free of costs and shall, if accepted, become the property of the 
lessor.
    (2) Navigation tapes showing the location(s) where samples were 
taken and test drilling conducted shall be retained for as long as the 
lease continues in force.
    (h) Lessees shall maintain records in which will be kept an 
accurate account of all ore and rock mined; all ore put through a mill; 
all mineral products produced; all ore and mineral products sold, 
transferred, used, or otherwise disposed of and to whom sold or 
transferred, and the inventory weight, assay value, moisture content, 
base sales price, dates, penalties, and price received. The percentage 
of each of the mineral products recovered and the percentages lost 
shall be shown. The records associated with activities on a lease shall 
be available to the Director for auditing.
    (i) When special forms or reports other than those referred to in 
the regulations in this part may be necessary, instructions for the 
filing of such forms or reports will be given by the Director.

Sec.  582.30  Right of use and easement.

    (a) A right of use and easement that includes any area subject to a 
lease issued or maintained under the Act shall be granted only after 
the lessee has been notified by the requestor and afforded the 
opportunity to comment on the request. A holder of a right under a 
right of use and easement shall exercise that right in accordance with 
the requirements of the regulations in this part. A right of use and 
easement shall be exercised only in a manner which does not interfere 
unreasonably with operations of any lessee on its lease.
    (b) Once a right of use and easement has been exercised, the right 
shall continue, beyond the termination of any lease on which it may be 
situated, as long as it is demonstrated to the Director that the right 
of use and easement is being exercised by the holder of the right and 
that the right of use and easement continues to serve the purpose 
specified in the grant. If the right of use and easement extends beyond 
the termination of any lease on which the right may be situated or if 
it is situated on an unleased portion of the OCS, the rights of all 
subsequent lessees shall be subject to such right. Upon termination of 
a right of use and easement, the holder of the right shall abandon the 
premises in the same manner that a lessee abandons activities on a 
lease to the satisfaction of the Director.

Sec.  582.31  [Reserved]

Subpart D--Payments

Sec.  582.40  Bonds.

    (a) Pursuant to the requirements for a bond in Sec.  581.33 of this 
title, prior to the commencement of any activity on a lease, the lessee 
shall submit a surety or personal bond to cover the lessee's royalty 
and other obligations under the lease as specified in this section.
    (b) All bonds furnished by a lessee or operator must be in a form 
approved by the Associate Director for Offshore Energy and Minerals 
Management. A single copy of the required form is to be executed by the 
principal or, in the case of surety bonds, by both the principal and an 
acceptable surety.
    (c) Only those surety bonds issued by qualified surety companies 
approved by the Department of the Treasury shall be accepted (see 
Department of Treasury Circular No. 570 and any supplemental or 
replacement circulars).
    (d) Personal bonds shall be accompanied by a cashier's check, 
certified check, or negotiable U.S. Treasury bonds of an equal value to 
the amount specified in the bond. Negotiable Treasury bonds shall be 
accompanied by a proper conveyance of full authority to the Director to 
sell such securities in case of default in the performance of the terms 
and conditions of the lease.
    (e) A bond in the minimum amount of $50,000 to cover the lessee's 
obligations under the lease shall be submitted prior to the 
commencement of any activity on a leasehold. A $50,000 bond shall not 
be required on a lease if the lessee already maintains or furnishes a 
$300,000 bond conditioned on compliance with the terms of leases for 
OCS minerals other than oil, gas, and sulphur held by the lessee on the 
OCS for the area in which the lease is located. A bond submitted 
pursuant to Sec.  556.58(a) of this chapter may be amended to include 
the aforementioned condition for compliance. Prior to approval of a 
Delineation, Testing, or Mining Plan, the bond amount shall be 
adjusted, if appropriate, to cover the operations and activities 
described in the proposed plan.
    (f) For the purposes of this section there are three areas:
    (1) The Gulf of Mexico and the area offshore the Atlantic Ocean;
    (2) The area offshore the Pacific Coast States of California, 
Oregon, Washington, and Hawaii; and
    (3) The area offshore the coast of Alaska.
    (g) A separate bond shall be required for each area. An operator's 
bond may

[[Page 64728]]

be submitted for a specific lease(s) in the same amount as the lessee's 
bond(s) applicable to the lease(s) involved.
    (h) Where, upon a default, the surety makes a payment to the United 
States of an obligation incurred under a lease, the face amount of the 
surety bond and the surety's liability thereunder shall be reduced by 
the amount of such payment.
    (i) After default, the principal shall, within 6 months after 
notice or within such shorter period as may be fixed by the Director, 
either post a new bond or increase the existing bond to the amount 
previously held. In lieu thereof, the principal may, within that time, 
file separate or substitute bonds for each lease. Failure to meet these 
requirements may result in a suspension of operations including 
production on leases covered by such bonds.
    (j) The Director shall not consent to termination of the period of 
liability of any bond unless an acceptable alternative bond has been 
filed or until all the terms and conditions of the lease covered by the 
bond have been met.

Sec.  582.41  Method of royalty calculation.

    In the event that the provisions of royalty management regulations 
in part 1206 of chapter XII do not apply to the specific commodities 
produced under regulations in this part, the lessee shall comply with 
procedures specified in the leasing notice.

Sec.  582.42  Payments.

    Rentals, royalties, and other payments due the Federal Government 
on leases for OCS minerals shall be paid and reports submitted by the 
payor for a lease in accordance with Sec.  581.26.

Subpart E--Appeals

Sec.  582.50  Appeals.

    See 30 CFR part 590 for instructions on how to appeal any order or 
decision that we issue under this part.

PART 585--RENEWABLE ENERGY AND ALTERNATE USES OF EXISTING 
FACILITIES ON THE OUTER CONTINENTAL SHELF

Subpart A--General Provisions
Sec.
585.100 Authority.
585.101 What is the purpose of this part?
585.102 What are BOEM's responsibilities under this part?
585.103 When may BOEM prescribe or approve departures from these 
regulations?
585.104 Do I need a BOEM lease or other authorization to produce or 
support the production of electricity or other energy product from a 
renewable energy resource on the OCS?
585.105 What are my responsibilities under this part?
585.106 Who can hold a lease or grant under this part?
585.107 How do I show that I am qualified to be a lessee or grant 
holder?
585.108 When must I notify BOEM if an action has been filed alleging 
that I am insolvent or bankrupt?
585.109 When must I notify BOEM of mergers, name changes, or changes 
of business form?
585.110 How do I submit plans, applications, reports, or notices 
required by this part?
585.111 When and how does BOEM charge me processing fees on a case-
by-case basis?
585.112 Definitions.
585.113 How will data and information obtained by BOEM under this 
part be disclosed to the public?
585.114 Paperwork Reduction Act statements--information collection.
585.115 Documents incorporated by reference.
585.116 Requests for information on the state of the offshore 
renewable energy industry.
585.117 [Reserved]
585.118 What are my appeal rights?
Subpart B--Issuance of OCS Renewable Energy Leases

General Lease Information

585.200 What rights are granted with a lease issued under this part?
585.201 How will BOEM issue leases?
585.202 What types of leases will BOEM issue?
585.203 With whom will BOEM consult before issuance of a lease?
585.204 What areas are available for leasing consideration?
585.205 How will leases be mapped?
585.206 What is the lease size?
585.207-585.209 [Reserved]

Competitive Lease Process

585.210 How does BOEM initiate the competitive leasing process?
585.211 What is the process for competitive issuance of leases?
585.212 What is the process BOEM will follow if there is reason to 
believe that competitors have withdrawn before the Final Sale Notice 
is issued?
585.213 What must I submit in response to a Request for Interest or 
a Call for Information and Nominations?
585.214 What will BOEM do with information from the Requests for 
Information or Calls for Information and Nominations?
585.215 What areas will BOEM offer in a lease sale?
585.216 What information will BOEM publish in the Proposed Sale 
Notice and Final Sale Notice?
585.217-585.219 [Reserved]

Competitive Lease Award Process

585.220 What auction format may BOEM use in a lease sale?
585.221 What bidding systems may BOEM use for commercial leases and 
limited leases?
585.222 What does BOEM do with my bid?
585.223 What does BOEM do if there is a tie for the highest bid?
585.224 What happens if BOEM accepts my bid?
585.225 What happens if my bid is rejected, and what are my appeal 
rights?
585.226-585.229 [Reserved]

Noncompetitive Lease Award Process

585.230 May I request a lease if there is no Call?
585.231 How will BOEM process my unsolicited request for a 
noncompetitive lease?
585.232 May I acquire a lease noncompetitively after responding to a 
Request for Interest or Call for Information and Nominations?
585.233 [Reserved]
585.234 [Reserved]

Commercial and Limited Lease Terms

585.235 If I have a commercial lease, how long will my lease remain 
in effect?
585.236 If I have a limited lease, how long will my lease remain in 
effect?
585.237 What is the effective date of a lease?
585.238 Are there any other renewable energy research activities 
that will be allowed on the OCS?
Subpart C--Rights-of-Way Grants and Rights-of-Use and Easement Grants 
for Renewable Energy Activities

ROW Grants and RUE Grants

585.300 What types of activities are authorized by ROW grants and 
RUE grants issued under this part?
585.301 What do ROW grants and RUE grants include?
585.302 What are the general requirements for ROW grant and RUE 
grant holders?
585.303 How long will my ROW grant or RUE grant remain in effect?
585.304 [Reserved]

Obtaining ROW Grants and RUE Grants

585.305 How do I request an ROW grant or RUE grant?
585.306 What action will BOEM take on my request?
585.307 How will BOEM determine whether competitive interest exists 
for ROW grants and RUE grants?
585.308 How will BOEM conduct an auction for ROW grants and RUE 
grants?
585.309 When will BOEM issue a noncompetitive ROW grant or RUE 
grant?
585.310 What is the effective date of an ROW grant or RUE grant?
585.311-585.314 [Reserved]

Financial Requirements for ROW Grants and RUE Grants

585.315 What deposits are required for a competitive ROW grant or 
RUE grant?
585.316 What payments are required for ROW grants or RUE grants?
Subpart D--Lease and Grant Administration

Noncompliance and Cessation Orders

585.400 What happens if I fail to comply with this part?

[[Page 64729]]

585.401 When may BOEM issue a cessation order?
585.402 What is the effect of a cessation order?
585.403 [Reserved]
585.404 [Reserved]

Designation of Operator

585.405 How do I designate an operator?
585.406 Who is responsible for fulfilling lease and grant 
obligations?
585.407 [Reserved]

Lease or Grant Assignment

585.408 May I assign my lease or grant interest?
585.409 How do I request approval of a lease or grant assignment?
585.410 How does an assignment affect the assignor's liability?
585.411 How does an assignment affect the assignee's liability?
585.412-585.414 [Reserved]

Lease or Grant Suspension

585.415 What is a lease or grant suspension?
585.416 How do I request a lease or grant suspension?
585.417 When may BOEM order a suspension?
585.418 How will BOEM issue a suspension?
585.419 What are my immediate responsibilities if I receive a 
suspension order?
585.420 What effect does a suspension order have on my payments?
585.421 How long will a suspension be in effect?
585.422-585.424 [Reserved]

Lease or Grant Renewal

585.425 May I obtain a renewal of my lease or grant before it 
terminates?
585.426 When must I submit my request for renewal?
585.427 How long is a renewal?
585.428 What effect does applying for a renewal have on my 
activities and payments?
585.429 What criteria will BOEM consider in deciding whether to 
renew a lease or grant?
585.430 [Reserved]
585.431 [Reserved]

Lease or Grant Termination

585.432 When does my lease or grant terminate?
585.433 What must I do after my lease or grant terminates?
585.434 [Reserved]

Lease or Grant Relinquishment

585.435 How can I relinquish a lease or a grant or parts of a lease 
or grant?

Lease or Grant Contraction

585.436 Can BOEM require lease or grant contraction?

Lease or Grant Cancellation

585.437 When can my lease or grant be canceled?
Subpart E--Payments and Financial Assurance Requirements

Payments

585.500 How do I make payments under this part?
585.501 What deposits must I submit for a competitively issued 
lease, ROW grant, or RUE grant?
585.502 What initial payment requirements must I meet to obtain a 
noncompetitive lease, ROW grant, or RUE grant?
585.503 What are the rent and operating fee requirements for a 
commercial lease?
585.504 How are my payments affected if I develop my lease in 
phases?
585.505 What are the rent and operating fee requirements for a 
limited lease?
585.506 What operating fees must I pay on a commercial lease?
585.507 What rent payments must I pay on a project easement?
585.508 What rent payments must I pay on ROW grants or RUE grants 
associated with renewable energy projects?
585.509 Who is responsible for submitting lease or grant payments to 
BOEM?
585.510 May BOEM reduce or waive my lease or grant payments?
585.511-585.514 [Reserved]

Financial Assurance Requirements for Commercial Leases

585.515 What financial assurance must I provide when I obtain my 
commercial lease?
585.516 What are the financial assurance requirements for each stage 
of my commercial lease?
585.517 How will BOEM determine the amounts of the supplemental and 
decommissioning financial assurance requirements associated with 
commercial leases?
585.518 [Reserved]
585.519 [Reserved]

Financial Assurance for Limited Leases, ROW Grants, and RUE Grants

585.520 What financial assurance must I provide when I obtain my 
limited lease, ROW grant, or RUE grant?
585.521 Do my financial assurance requirements change as activities 
progress on my limited lease or grant?
585.522-585.524 [Reserved]

Requirements for Financial Assurance Instruments

585.525 What general requirements must a financial assurance 
instrument meet?
585.526 What instruments other than a surety bond may I use to meet 
the financial assurance requirement?
585.527 May I demonstrate financial strength and reliability to meet 
the financial assurance requirement for lease or grant activities?
585.528 May I use a third-party guaranty to meet the financial 
assurance requirement for lease or grant activities?
585.529 Can I use a lease- or grant-specific decommissioning account 
to meet the financial assurance requirements related to 
decommissioning?

Changes in Financial Assurance

585.530 What must I do if my financial assurance lapses?
585.531 What happens if the value of my financial assurance is 
reduced?
585.532 What happens if my surety wants to terminate the period of 
liability of my bond?
585.533 How does my surety obtain cancellation of my bond?
585.534 When may BOEM cancel my bond?
585.535 Why might BOEM call for forfeiture of my bond?
585.536 How will I be notified of a call for forfeiture?
585.537 How will BOEM proceed once my bond or other security is 
forfeited?
585.538 [Reserved]
585.539 [Reserved]

Revenue Sharing with States

585.540 How will BOEM equitably distribute revenues to States?
585.541 What is a qualified project for revenue sharing purposes?
585.542 What makes a State eligible for payment of revenues?
585.543 Example of how the inverse distance formula works.
Subpart F--Plans and Information Requirements
585.600 What plans and information must I submit to BOEM before I 
conduct activities on my lease or grant?
585.601 When am I required to submit my plans to BOEM?
585.602 What records must I maintain?
585.603 [Reserved]
585.604 [Reserved]

Site Assessment Plan and Information Requirements for Commercial Leases

585.605 What is a Site Assessment Plan (SAP)?
585.606 What must I demonstrate in my SAP?
585.607 How do I submit my SAP?
585.608 [Reserved]
585.609 [Reserved]

Contents of the Site Assessment Plan

585.610 What must I include in my SAP?
585.611 What information must I submit with my SAP to assist BOEM in 
complying with NEPA and other relevant laws?
585.612 How will my SAP be processed for Federal consistency under 
the Coastal Zone Management Act?
585.613 How will BOEM process my SAP?

Activities Under an Approved SAP

585.614 When may I begin conducting activities under my approved 
SAP?
585.615 What other reports or notices must I submit to BOEM under my 
approved SAP?
585.616 [Reserved]
585.617 What activities require a revision to my SAP, and when will 
BOEM approve the revision?
585.618 What must I do upon completion of approved site assessment 
activities?
585.619 [Reserved]

[[Page 64730]]

Construction and Operations Plan for Commercial Leases

585.620 What is a Construction and Operations Plan (COP)?
585.621 What must I demonstrate in my COP?
585.622 How do I submit my COP?
585.623-585.625 [Reserved]

Contents of the Construction and Operations Plan

585.626 What must I include in my COP?
585.627 What information and certifications must I submit with my 
COP to assist the BOEM in complying with NEPA and other relevant 
laws?
585.628 How will BOEM process my COP?
585.629 May I develop my lease in phases?
585.630 [Reserved]

Activities Under an Approved COP

585.631 When must I initiate activities under an approved COP?
585.632 What documents must I submit before I may construct and 
install facilities under my approved COP?
585.633 How do I comply with my COP?
585.634 What activities require a revision to my COP, and when will 
BOEM approve the revision?
585.635 What must I do if I cease activities approved in my COP 
before the end of my commercial lease?
585.636 What notices must I provide BOEM following approval of my 
COP?
585.637 When may I commence commercial operations on my commercial 
lease?
585.638 What must I do upon completion of my commercial operations 
as approved in my COP or FERC license?
585.639 [Reserved]

General Activities Plan Requirements for Limited Leases, ROW Grants, 
and RUE Grants

585.640 What is a General Activities Plan (GAP)?
585.641 What must I demonstrate in my GAP?
585.642 How do I submit my GAP?
585.643 [Reserved]
585.644 [Reserved]

Contents of the General Activities Plan

585.645 What must I include in my GAP?
585.646 What information and certifications must I submit with my 
GAP to assist BOEM in complying with NEPA and other relevant laws?
585.647 How will my GAP be processed for Federal consistency under 
the Coastal Zone Management Act?
585.648 How will BOEM process my GAP?
585.649 [Reserved]

Activities Under an Approved GAP

585.650 When may I begin conducting activities under my GAP?
585.651 When may I construct complex or significant OCS facilities 
on my limited lease or any facilities on my project easement 
proposed under my GAP?
585.652 How long do I have to conduct activities under an approved 
GAP?
585.653 What other reports or notices must I submit to BOEM under my 
approved GAP?
585.654 [Reserved]
585.655 What activities require a revision to my GAP, and when will 
BOEM approve the revision?
585.656 What must I do if I cease activities approved in my GAP 
before the end of my term?
585.657 What must I do upon completion of approved activities under 
my GAP?

Cable and Pipeline Deviations

585.658 Can my cable or pipeline construction deviate from my 
approved COP or GAP?
585.659 What requirements must I include in my SAP, COP, or GAP 
regarding air quality?
Subpart G--Facility Design, Fabrication, and Installation

Reports

585.700 What reports must I submit to BOEM before installing 
facilities described in my approved SAP, COP, or GAP?
585.701 What must I include in my Facility Design Report?
585.702 What must I include in my Fabrication and Installation 
Report?
585.703 What reports must I submit for project modifications and 
repairs?
585.704 [Reserved]

Certified Verification Agent

585.705 When must I use a Certified Verification Agent (CVA)?
585.706 How do I nominate a CVA for BOEM approval?
585.707 What are the CVA's primary duties for facility design 
review?
585.708 What are the CVA's or project engineer's primary duties for 
fabrication and installation review?
585.709 When conducting onsite fabrication inspections, what must 
the CVA or project engineer verify?
585.710 When conducting onsite installation inspections, what must 
the CVA or project engineer do?
585.711 [Reserved]
585.712 What are the CVA's or project engineer's reporting 
requirements?
585.713 What must I do after the CVA or project engineer confirms 
conformance with the Fabrication and Installation Report on my 
commercial lease?
585.714 What records relating to SAPs, COPs, and GAPs must I keep?
Subpart H--Environmental and Safety Management, Inspections, and 
Facility Assessments for Activities Conducted Under SAPs, COPs and GAPs
585.800 How must I conduct my activities to comply with safety and 
environmental requirements?
585.801 How must I conduct my approved activities to protect marine 
mammals, threatened and endangered species, and designated critical 
habitat?
585.802 What must I do if I discover a potential archaeological 
resource while conducting my approved activities?
585.803 How must I conduct my approved activities to protect 
essential fish habitats identified and described under the Magnuson-
Stevens Fishery Conservation and Management Act?
585.804-585.809 [Reserved]

Safety Management Systems

585.810 What must I include in my Safety Management System?
585.811 When must I follow my Safety Management System?
585.812 [Reserved]

Maintenance and Shutdowns

585.813 When do I have to report removing equipment from service?
585.814 [Reserved]

Equipment Failure and Adverse Environmental Effects

585.815 What must I do if I have facility damage or an equipment 
failure?
585.816 What must I do if environmental or other conditions 
adversely affect a cable, pipeline, or facility?
585.817-585.819 [Reserved]

Inspections and Assessments

585.820 Will BOEM conduct inspections?
585.821 Will BOEM conduct scheduled and unscheduled inspections?
585.822 What must I do when BOEM conducts an inspection?
585.823 Will BOEM reimburse me for my expenses related to 
inspections?
585.824 How must I conduct self-inspections?
585.825 When must I assess my facilities?
585.826-585.829 [Reserved]

Incident Reporting and Investigation

585.830 What are my incident reporting requirements?
585.831 What incidents must I report, and when must I report them?
585.832 How do I report incidents requiring immediate notification?
585.833 What are the reporting requirements for incidents requiring 
written notification?
Subpart I--Decommissioning

Decommissioning Obligations and Requirements

585.900 Who must meet the decommissioning obligations in this 
subpart?
585.901 When do I accrue decommissioning obligations?
585.902 What are the general requirements for decommissioning for 
facilities authorized under my SAP, COP, or GAP?
585.903 What are the requirements for decommissioning FERC-licensed 
hydrokinetic facilities?
585.904 Can I request a departure from the decommissioning 
requirements?

Decommissioning Applications

585.905 When must I submit my decommissioning application?
585.906 What must my decommissioning application include?
585.907 How will BOEM process my decommissioning application?

[[Page 64731]]

585.908 What must I include in my decommissioning notice?

Facility Removal

585.909 When may BOEM authorize facilities to remain in place 
following termination of a lease or grant?
585.910 What must I do when I remove my facility?
585.911 [Reserved]

Decommissioning Report

585.912 After I remove a facility, cable, or pipeline, what 
information must I submit?

Compliance with an Approved Decommissioning Application

585.913 What happens if I fail to comply with my approved 
decommissioning application?
Subpart J--Rights of Use and Easement for Energy- and Marine-Related 
Activities Using Existing OCS Facilities

Regulated Activities

585.1000 What activities does this subpart regulate?
585.1001-585.1003 [Reserved]

Requesting an Alternate Use RUE

585.1004 What must I do before I request an Alternate Use RUE?
585.1005 How do I request an Alternate Use RUE?
585.1006 How will BOEM decide whether to issue an Alternate Use RUE?
585.1007 What process will BOEM use for competitively offering an 
Alternate Use RUE?
585.1008 [Reserved]
585.1009 [Reserved]

Alternate Use RUE Administration

585.1010 How long may I conduct activities under an Alternate Use 
RUE?
585.1011 What payments are required for an Alternate Use RUE?
585.1012 What financial assurance is required for an Alternate Use 
RUE?
585.1013 Is an Alternate Use RUE assignable?
585.1014 When will BOEM suspend an Alternate Use RUE?
585.1015 How do I relinquish an Alternate Use RUE?
585.1016 When will an Alternate Use RUE be cancelled?
585.1017 [Reserved]

Decommissioning an Alternate Use RUE

585.1018 Who is responsible for decommissioning an OCS facility 
subject to an Alternate Use RUE?
585.1019 What are the decommissioning requirements for an Alternate 
Use RUE?

    Authority: 43 U.S.C. 1331 et seq., 43 U.S.C. 1337.

Subpart A--General Provisions

Sec.  585.100  Authority.

    The authority for this part derives from amendments to subsection 8 
of the Outer Continental Shelf Lands Act (OCS Lands Act) (43 U.S.C. 
1337), as set forth in section 388(a) of the Energy Policy Act of 2005 
(EPAct) (Pub. L. 109-58). The Secretary of the Interior delegated to 
the Bureau of Ocean Energy Management (BOEM) the authority to regulate 
activities under section 388(a) of the EPAct. These regulations 
specifically apply to activities that:
    (a) Produce or support production, transportation, or transmission 
of energy from sources other than oil and gas; or
    (b) Use, for energy-related purposes or for other authorized 
marine-related purposes, facilities currently or previously used for 
activities authorized under the OCS Lands Act.

Sec.  585.101  What is the purpose of this part?

    The purpose of this part is to:
    (a) Establish procedures for issuance and administration of leases, 
right-of-way (ROW) grants, and right-of-use and easement (RUE) grants 
for renewable energy production on the Outer Continental Shelf (OCS) 
and RUEs for the alternate use of OCS facilities for energy or marine-
related purposes;
    (b) Inform you and third parties of your obligations when you 
undertake activities authorized in this part; and
    (c) Ensure that renewable energy activities on the OCS and 
activities involving the alternate use of OCS facilities for energy or 
marine-related purposes are conducted in a safe and environmentally 
sound manner, in conformance with the requirements of subsection 8(p) 
of the OCS Lands Act, other applicable laws and regulations, and the 
terms of your lease, ROW grant, RUE grant, or Alternate Use RUE grant.
    (d) This part will not convey access rights for oil, gas, or other 
minerals.

Sec.  585.102  What are BOEM's responsibilities under this part?

    (a) BOEM will ensure that any activities authorized in this part 
are carried out in a manner that provides for:
    (1) Safety;
    (2) Protection of the environment;
    (3) Prevention of waste;
    (4) Conservation of the natural resources of the OCS;
    (5) Coordination with relevant Federal agencies (including, in 
particular, those agencies involved in planning activities that are 
undertaken to avoid conflicts among users and maximize the economic and 
ecological benefits of the OCS, including multifaceted spatial planning 
efforts);
    (6) Protection of National security interests of the United States;
    (7) Protection of the rights of other authorized users of the OCS;
    (8) A fair return to the United States;
    (9) Prevention of interference with reasonable uses (as determined 
by the Secretary or Director) of the exclusive economic zone, the high 
seas, and the territorial seas;
    (10) Consideration of the location of and any schedule relating to 
a lease or grant under this part for an area of the OCS, and any other 
use of the sea or seabed;
    (11) Public notice and comment on any proposal submitted for a 
lease or grant under this part; and
    (12) Oversight, inspection, research, monitoring, and enforcement 
of activities authorized by a lease or grant under this part.
    (b) BOEM will require compliance with all applicable laws, 
regulations, other requirements, and the terms of your lease or grant 
under this part and approved plans. BOEM will approve, disapprove, or 
approve with conditions any plans, applications, or other documents 
submitted to BOEM for approval under the provisions of this part.
    (c) Unless otherwise provided in this part, BOEM may give oral 
directives or decisions whenever prior BOEM approval is required under 
this part. BOEM will document in writing any such oral directives 
within 10 business days.
    (d) BOEM will establish practices and procedures to govern the 
collection of all payments due to the Federal Government, including any 
cost recovery fees, rents, operating fees, and other fees or payments. 
BOEM will do this in accordance with the terms of this part, the 
leasing notice, the lease or grant under this part, and applicable 
Office of Natural Resources Revenue regulations or guidance.
    (e) BOEM will provide for coordination and consultation with the 
Governor of any State or the executive of any local government or 
Indian Tribe that may be affected by a lease, easement, or ROW under 
this subsection. BOEM may invite any affected State Governor, 
representative of an affected Indian Tribe, and affected local 
government executive to join in establishing a task force or other 
joint planning or coordination agreement in carrying out our 
responsibilities under this part.

Sec.  585.103  When may BOEM prescribe or approve departures from these 
regulations?

    (a) BOEM may prescribe or approve departures from these regulations 
when departures are necessary to:
    (1) Facilitate the appropriate activities on a lease or grant under 
this part;
    (2) Conserve natural resources;
    (3) Protect life (including human and wildlife), property, or the 
marine, coastal, or human environment; or

[[Page 64732]]

    (4) Protect sites, structures, or objects of historical or 
archaeological significance.
    (b) Any departure approved under this section and its rationale 
must:
    (1) Be consistent with subsection 8(p) of the OCS Lands Act;
    (2) Protect the environment and the public health and safety to the 
same degree as if there was no approved departure from the regulations;
    (3) Not impair the rights of third parties; and
    (4) Be documented in writing.

Sec.  585.104  Do I need a BOEM lease or other authorization to produce 
or support the production of electricity or other energy product from a 
renewable energy resource on the OCS?

    Except as otherwise authorized by law, it will be unlawful for any 
person to construct, operate, or maintain any facility to produce, 
transport, or support generation of electricity or other energy product 
derived from a renewable energy resource on any part of the OCS, except 
under and in accordance with the terms of a lease, easement, or ROW 
issued pursuant to the OCS Lands Act.

Sec.  585.105  What are my responsibilities under this part?

    As a lessee, applicant, operator, or holder of a ROW grant, RUE 
grant, or Alternate Use RUE grant, you must:
    (a) Design your projects and conduct all activities in a manner 
that ensures safety and will not cause undue harm or damage to natural 
resources, including their physical, atmospheric, and biological 
components to the extent practicable; and take measures to prevent 
unauthorized discharge of pollutants including marine trash and debris 
into the offshore environment.
    (b) Submit requests, applications, plans, notices, modifications, 
and supplemental information to BOEM as required by this part;
    (c) Follow up, in writing, any oral request or notification you 
made, within 3 business days;
    (d) Comply with the terms, conditions, and provisions of all 
reports and notices submitted to BOEM, and of all plans, revisions, and 
other BOEM approvals, as provided in this part;
    (e) Make all applicable payments on time;
    (f) Comply with the DOI's nonprocurement debarment regulations at 2 
CFR part 1400;
    (g) Include the requirement to comply with 2 CFR part 1400 in all 
contracts and transactions related to a lease or grant under this part;
    (h) Conduct all activities authorized by the lease or grant in a 
manner consistent with the provisions of subsection 8(p) of the OCS 
Lands Act;
    (i) Compile, retain, and make available to BOEM representatives, 
within the time specified by BOEM, any data and information related to 
the site assessment, design, and operations of your project; and
    (j) Respond to requests from the Director in a timely manner.

Sec.  585.106  Who can hold a lease or grant under this part?

    (a) You may hold a lease or grant under this part if you can 
demonstrate that you have the technical and financial capabilities to 
conduct the activities authorized by the lease or grant and you are 
a(n):
    (1) Citizen or national of the United States;
    (2) Alien lawfully admitted for permanent residence in the United 
States as defined in 8 U.S.C. 1101(a)(20);
    (3) Private, public, or municipal corporations organized under the 
laws of any State of the United States, the District of Columbia, or 
any territory or insular possession subject to U.S. jurisdiction;
    (4) Association of such citizens, nationals, resident aliens, or 
corporations;
    (5) Executive Agency of the United States as defined in section 105 
of Title 5 of the U.S. Code;
    (6) State of the United States; and
    (7) Political subdivision of States of the United States.
    (b) You may not hold a lease or grant under this part or acquire an 
interest in a lease or grant under this part if:
    (1) You or your principals are excluded or disqualified from 
participating in transactions covered by the Federal nonprocurement 
debarment and suspension system (2 CFR part 1400), unless BOEM 
explicitly has approved an exception for this transaction;
    (2) BOEM determines or has previously determined after notice and 
opportunity for a hearing that you or your principals have failed to 
meet or exercise due diligence under any OCS lease or grant; or
    (3) BOEM determines or has previously determined after notice and 
opportunity for a hearing that you:
    (i) Remained in violation of the terms and conditions of any lease 
or grant issued under the OCS Lands Act for a period extending longer 
than 30 days (or such other period BOEM allowed for compliance) after 
BOEM directed you to comply; and
    (ii) You took no action to correct the noncompliance within that 
time period.

Sec.  585.107  How do I show that I am qualified to be a lessee or 
grant holder?

    (a) You must demonstrate your technical and financial capability to 
construct, operate, maintain, and terminate/decommission projects for 
which you are requesting authorization. Documentation can include:
    (1) Descriptions of international or domestic experience with 
renewable energy projects or other types of electric-energy-related 
projects; and
    (2) Information establishing access to sufficient capital to carry 
out development.
    (b) An individual must submit a written statement of citizenship 
status attesting to U.S. citizenship. It does not need to be notarized 
nor give the age of individual. A resident alien may submit a photocopy 
of the Immigration and Naturalization Service form evidencing legal 
status of the resident alien.
    (c) A corporation or association must submit evidence, as specified 
in the table in paragraph (d) of this section, acceptable to BOEM that:
    (1) It is qualified to hold leases or grants under this part;
    (2) It is authorized to conduct business under the laws of its 
State;
    (3) It is authorized to hold leases or grants on the OCS under the 
operating rules of its business; and
    (4) The persons holding the titles listed are authorized to bind 
the corporation or association when conducting business with BOEM.
    (d) Acceptable evidence under paragraph (c) of this section 
includes, but is not limited to the following:

----------------------------------------------------------------------------------------------------------------
 Requirements to qualify to hold leases or                    Ltd.          Gen.
            grants on the OCS:                  Corp.        Prtnsp.       Prtnsp.         LLC          Trust
----------------------------------------------------------------------------------------------------------------
(1) Original certificate or certified copy           XX   ............  ............  ............  ............
 from the State of incorporation stating
 the name of the corporation exactly as it
 must appear on all legal documents.
(2) Certified statement by Secretary/                XX   ............  ............  ............  ............
 Assistant Secretary over corporate seal,
 certifying that the corporation is
 authorized to hold OCS leases.

[[Page 64733]]

 
(3) Evidence of authority of titled                  XX   ............  ............  ............  ............
 positions to bind corporation, certified
 by Secretary/Assistant Secretary over
 corporate seal, including the following:
    (i) Certified copy of resolution of
     the board of directors with titles of
     officers authorized to bind
     corporation.
    (ii) Certified copy of resolutions
     granting corporate officer authority
     to issue a power of attorney.
    (iii) Certified copy of power of
     attorney or certified copy of
     resolution granting power of
     attorney.
(4) Original certificate or certified copy  ............           XX            XX            XX   ............
 of partnership or organization paperwork
 registering with the appropriate State
 official.
(5) Copy of articles of partnership or      ............           XX            XX            XX   ............
 organization evidencing filing with
 appropriate Secretary of State, certified
 by Secretary/Assistant Secretary of
 partnership or member or manager of LLC.
(6) Original certificate or certified copy  ............           XX            XX            XX   ............
 evidencing State where partnership or LLC
 is registered. Statement of authority to
 hold OCS leases, certified by Secretary/
 Assistant Secretary, OR original
 paperwork registering with the
 appropriate State official.
(7) Statements from each partner or LLC     ............           XX            XX            XX   ............
 member indicating the following:
    (i) If a corporation or partnership,
     statement of State of organization
     and authorization to hold OCS leases,
     certified by Secretary/Assistant
     Secretary over corporate seal, if a
     corporation.
    (ii) If an individual, a statement of
     citizenship.
(8) Statement from general partner,         ............           XX   ............  ............  ............
 certified by Secretary/Assistant
 Secretary that:
    (i) Each individual limited partner is
     a U.S. citizen and;
    (ii) Each corporate limited partner or
     other entity is incorporated or
     formed and organized under the laws
     of a U.S. State or territory.
(9) Evidence of authority to bind           ............           XX            XX            XX   ............
 partnership or LLC, if not specified in
 partnership agreement, articles of
 organization, or LLC regulations, i.e.,
 certificates of authority from Secretary/
 Assistant Secretary reflecting authority
 of officers.
(10) Listing of members of LLC certified    ............  ............  ............           XX   ............
 by Secretary/Assistant Secretary or any
 member or manager of LLC.
(11) Copy of trust agreement or document    ............  ............  ............  ............           XX
 establishing the trust and all
 amendments, properly certified by the
 trustee with reference to where the
 original documents are filed.
(12) Statement indicating the law under     ............  ............  ............  ............           XX
 which the trust is established and that
 the trust is authorized to hold OCS
 leases or grants.
----------------------------------------------------------------------------------------------------------------

     (e) A local, State, or Federal executive entity must submit a 
written statement that:
    (1) It is qualified to hold leases or grants under this part; and
    (2) The person(s) acting on behalf of the entity is authorized to 
bind the entity when conducting business with us.
    (f) BOEM may require you to submit additional information at any 
time considering your bid or request for a noncompetitive lease.

Sec.  585.108  When must I notify BOEM if an action has been filed 
alleging that I am insolvent or bankrupt?

    You must notify BOEM within 3 business days after you learn of any 
action filed alleging that you are insolvent or bankrupt.

Sec.  585.109  When must I notify BOEM of mergers, name changes, or 
changes of business form?

    You must notify BOEM in writing of any merger, name change, or 
change of business form. You must notify BOEM as soon as practicable 
following the merger, name change, or change in business form, but no 
later than 120 days after the earliest of either the effective date, or 
the date of filing the change or action with the Secretary of the State 
or other authorized official in the State of original registry.

Sec.  585.110  How do I submit plans, applications, reports, or notices 
required by this part?

    (a) You must submit all plans, applications, reports, or notices 
required by this part to BOEM at the following address: Associate 
Director, Bureau of Ocean Energy Management, MS-4001, 381 Elden Street, 
Herndon, VA 20170.
    (b) Unless otherwise stated, you must submit one paper copy and one 
electronic copy of all plans, applications, reports, or notices 
required by this part.

Sec.  585.111  When and how does BOEM charge me processing fees on a 
case-by-case basis?

    (a) BOEM will charge a processing fee on a case-by-case basis under 
the procedures in this section with regard to any application or 
request under this part if we decide at any time that the preparation 
of a particular document or study is necessary for the application or 
request and it will have a unique processing cost, such as the 
preparation of an Environmental Assessment (EA) or Environmental Impact 
Statement (EIS).
    (1) Processing costs will include contract oversight and efforts to 
review and approve documents prepared by contractors, whether the 
contractor is paid directly by the applicant or through BOEM.
    (2) We may apply a standard overhead rate to direct processing 
costs.
    (b) We will assess the ongoing processing fee for each individual 
application or request according to the following procedures:

[[Page 64734]]

    (1) Before we process your application or request, we will give you 
a written estimate of the proposed fee based on reasonable processing 
costs.
    (2) You may comment on the proposed fee.
    (3) You may:
    (i) Ask for our approval to perform, or to directly pay a 
contractor to perform, all or part of any document, study, or other 
activity according to standards we specify, thereby reducing our costs 
for processing your application or request; or
    (ii) Ask to pay us to perform, or contract for, all or part of any 
document, study, or other activity.
    (4) We will then give you the final estimate of the processing fee 
amount with payment terms and instructions after considering your 
comments and any BOEM-approved work you will do.
    (i) If we encounter higher or lower processing costs than 
anticipated, we will re-estimate our reasonable processing costs 
following the procedures in paragraphs (b)(1) through (4) of this 
section, but we will not stop ongoing processing unless you do not pay 
in accordance with paragraph (b)(5) of this section.
    (ii) Once processing is complete, we will refund to you the amount 
of money that we did not spend on processing costs.
    (5)(i) Consistent with the payment and billing terms provided in 
the final estimate, we will periodically estimate what our reasonable 
processing costs will be for a specific period and will bill you for 
that period. Payment is due to us 30 days after you receive your bill. 
We will stop processing your document if you do not pay the bill by the 
date payment is due.
    (ii) If a periodic payment turns out to be more or less than our 
reasonable processing costs for the period, we will adjust the next 
billing accordingly or make a refund. Do not deduct any amount from a 
payment without our prior written approval.
    (6) You must pay the entire fee before we will issue the final 
document or take final action on your application or request.
    (7) You may appeal our estimated processing costs in accordance 
with the regulations in 43 CFR part 4. We will not process the document 
further until the appeal is resolved, unless you pay the fee under 
protest while the appeal is pending. If the appeal results in a 
decision changing the proposed fee, we will adjust the fee in 
accordance with paragraph (b)(5)(ii) of this section. If we adjust the 
fee downward, we will not pay interest.

Sec.  585.112  Definitions.

    Terms used in this part have the meanings as defined in this 
section:
    Affected local government means with respect to any activities 
proposed, conducted, or approved under this part, any locality--
    (1) That is, or is proposed to be, the site of gathering, 
transmitting, or distributing electricity or other energy product, or 
is otherwise receiving, processing, refining, or transshipping product, 
or services derived from activities approved under this part;
    (2) That is used, or is proposed to be used, as a support base for 
activities approved under this part; or
    (3) In which there is a reasonable probability of significant 
effect on land or water uses from activities approved under this part.
    Affected State means with respect to any activities proposed, 
conducted, or approved under this part, any coastal State--
    (1) That is, or is proposed to be, the site of gathering, 
transmitting, or distributing energy or is otherwise receiving, 
processing, refining, or transshipping products, or services derived 
from activities approved under this part;
    (2) That is used, or is scheduled to be used, as a support base for 
activities approved under this part; or
    (3) In which there is a reasonable probability of significant 
effect on land or water uses from activities approved under this part.
    Alternate Use refers to the energy- or marine-related use of an 
existing OCS facility for activities not otherwise authorized by this 
subchapter or other applicable law.
    Alternate Use RUE means a right-of-use and easement issued for 
activities authorized under subpart J of this part.
    Archaeological resource means any material remains of human life or 
activities that are at least 50 years of age and that are of 
archaeological interest (i.e., which are capable of providing 
scientific or humanistic understanding of past human behavior, cultural 
adaptation, and related topics through the application of scientific or 
scholarly techniques, such as controlled observation, contextual 
measurement, controlled collection, analysis, interpretation, and 
explanation).
    Best available and safest technology means the best available and 
safest technologies that BOEM determines to be economically feasible 
wherever failure of equipment would have a significant effect on 
safety, health, or the environment.
    Best management practices mean practices recognized within their 
respective industry, or by Government, as one of the best for achieving 
the desired output while reducing undesirable outcomes.
    BOEM means Bureau of Ocean Energy Management of the Department of 
the Interior.
    Certified Verification Agent (CVA) means an individual or 
organization, experienced in the design, fabrication, and installation 
of offshore marine facilities or structures, who will conduct specified 
third-party reviews, inspections, and verifications in accordance with 
this part.
    Coastline means the same as the term ``coast line'' in section 2 of 
the Submerged Lands Act (43 U.S.C. 1301(c)).
    Commercial activities mean, for renewable energy leases and grants, 
all activities associated with the generation, storage, or transmission 
of electricity or other energy product from a renewable energy project 
on the OCS, and for which such electricity or other energy product is 
intended for distribution, sale, or other commercial use, except for 
electricity or other energy product distributed or sold pursuant to 
technology-testing activities on a limited lease. This term also 
includes activities associated with all stages of development, 
including initial site characterization and assessment, facility 
construction, and project decommissioning.
    Commercial lease means a lease issued under this part that 
specifies the terms and conditions under which a person can conduct 
commercial activities.
    Commercial operations mean the generation of electricity or other 
energy product for commercial use, sale, or distribution on a 
commercial lease.
    Decommissioning means removing BOEM-approved facilities and 
returning the site of the lease or grant to a condition that meets the 
requirements under subpart I of this part.
    Director means the Director of the Bureau of Ocean Energy 
Management (BOEM), of the U.S. Department of the Interior, or an 
official authorized to act on the Director's behalf.
    Distance means the minimum great circle distance.
    Eligible State means a coastal State having a coastline (measured 
from the nearest point) no more than 15 miles from the geographic 
center of a qualified project area.
    Facility means an installation that is permanently or temporarily 
attached to the seabed of the OCS. Facilities include any structures; 
devices; appurtenances; gathering, transmission, and distribution 
cables; pipelines; and

[[Page 64735]]

permanently moored vessels. Any group of OCS installations 
interconnected with walkways, or any group of installations that 
includes a central or primary installation with one or more satellite 
or secondary installations, is a single facility. BOEM may decide that 
the complexity of the installations justifies their classification as 
separate facilities.
    Geographic center of a project means the centroid (geometric center 
point) of a qualified project area. The centroid represents the point 
that is the weighted average of coordinates of the same dimension 
within the mapping system, with the weights determined by the density 
function of the system. For example, in the case of a project area 
shaped as a rectangle or other parallelogram, the geographic center 
would be that point where lines between opposing corners intersect. The 
geographic center of a project could be outside the project area itself 
if that area is irregularly shaped.
    Governor means the Governor of a State or the person or entity 
lawfully designated by or under State law to exercise the powers 
granted to a Governor.
    Grant means a right-of-way, right-of-use and easement, or alternate 
use right-of-use and easement issued under the provisions of this part.
    Human environment means the physical, social, and economic 
components, conditions, and factors that interactively determine the 
state, condition, and quality of living conditions, employment, and 
health of those affected, directly or indirectly, by activities 
occurring on the OCS.
    Income, unless clearly specified to the contrary, refers to the 
money received by the project owner or holder of the lease or grant 
issued under this part. The term does not mean that project receipts 
exceed project expenses.
    Lease means an agreement authorizing the use of a designated 
portion of the OCS for activities allowed under this part. The term 
also means the area covered by that agreement, when the context 
requires.
    Lessee means the holder of a lease, a BOEM-approved assignee, and, 
when describing the conduct required of parties engaged in activities 
on the lease, it also refers to the operator and all persons authorized 
by the holder of the lease or operator to conduct activities on the 
lease.
    Limited lease means a lease issued under this part that specifies 
the terms and conditions under which a person may conduct activities on 
the OCS that support the production of energy, but do not result in the 
production of electricity or other energy product for sale, 
distribution, or other commercial use exceeding a limit specified in 
the lease.
    Marine environment means the physical, atmospheric, and biological 
components, conditions, and factors that interactively determine the 
productivity, state, condition, and quality of the marine ecosystem. 
These include the waters of the high seas, the contiguous zone, 
transitional and intertidal areas, salt marshes, and wetlands within 
the coastal zone and on the OCS.
    Miles mean nautical miles, as opposed to statute miles.
    Natural resources include, without limiting the generality thereof, 
renewable energy, oil, gas, and all other minerals (as defined in 
section 2(q) of the OCS Lands Act), and marine animal and marine plant 
life.
    Operator means the individual, corporation, or association having 
control or management of activities on the lease or grant under this 
part. The operator may be a lessee, grant holder, or a contractor 
designated by the lessee or holder of a grant under this part.
    Outer Continental Shelf (OCS) means all submerged lands lying 
seaward and outside of the area of lands beneath navigable waters, as 
defined in section 2 of the Submerged Lands Act (43 U.S.C. 1301), whose 
subsoil and seabed appertain to the United States and are subject to 
its jurisdiction and control.
    Person means, in addition to a natural person, an association 
(including partnerships and joint ventures); a Federal agency; a State; 
a political subdivision of a State; a Native American Tribal 
government; or a private, public, or municipal corporation.
    Project, for the purposes of defining the source of revenues to be 
shared, means a lease ROW, RUE, or Alternate Use RUE on which the 
activities authorized under this part are conducted on the OCS. The 
term ``project'' may be used elsewhere in this rule to refer to these 
same authorized activities, the facilities used to conduct these 
activities, or to the geographic area of the project, i.e., the project 
area.
    Project area means the geographic surface leased, or granted, for 
the purpose of a specific project. If OCS acreage is granted for a 
project under some form of agreement other than a lease (i.e., a ROW, 
RUE, or Alternate Use RUE issued under this part), the Federal acreage 
granted would be considered the project area. To avoid distortions in 
the calculation of the geometric center of the project area, project 
easements issued under this part are not considered part of the 
qualified project's area.
    Project easement means an easement to which, upon approval of your 
Construction and Operations Plan (COP) or General Activities Plan 
(GAP), you are entitled as part of the lease for the purpose of 
installing, gathering, transmission, and distribution cables, 
pipelines, and appurtenances on the OCS as necessary for the full 
enjoyment of the lease.
    Renewable Energy means energy resources other than oil and gas and 
minerals as defined in 30 CFR part 580. Such resources include, but are 
not limited to, wind, solar, and ocean waves, tides, and current.
    Revenues mean bonuses, rents, operating fees, and similar payments 
made in connection with a project or project area. It does not include 
administrative fees such as those assessed for cost recovery, civil 
penalties, and forfeiture of financial assurance.
    Right-of-use and easement (RUE) grant means an easement issued by 
BOEM under this part that authorizes use of a designated portion of the 
OCS to support activities on a lease or other use authorization for 
renewable energy activities. The term also means the area covered by 
the authorization.
    Right-of-way (ROW) grant means an authorization issued by BOEM 
under this part to use a portion of the OCS for the construction and 
use of a cable or pipeline for the purpose of gathering, transmitting, 
distributing, or otherwise transporting electricity or other energy 
product generated or produced from renewable energy, but does not 
constitute a project easement under this part. The term also means the 
area covered by the authorization.
    Secretary means the Secretary of the Interior or an official 
authorized to act on the Secretary's behalf.
    Significant archaeological resource means an archaeological 
resource that meets the criteria of significance for eligibility for 
listing in the National Register of Historic Places, as defined in 36 
CFR 60.4 or its successor.
    Site assessment activities mean those initial activities conducted 
to characterize a site on the OCS, such as resource assessment surveys 
(e.g., meteorological and oceanographic) or technology testing, 
involving the installation of bottom-founded facilities.
    You and your refer to an applicant, lessee, the operator, a 
designated agent of the lessee(s) or designated operator, ROW grant 
holder, RUE grant holder, or Alternate Use RUE grant holder under this 
part, or the possessive of each, depending on the context.

[[Page 64736]]

    We, us, and our refer to the Bureau of Ocean Energy Management of 
the Department of the Interior, or its possessive, depending on the 
context.

Sec.  585.113  How will data and information obtained by BOEM under 
this part be disclosed to the public?

    (a) BOEM will make data and information available in accordance 
with the requirements and subject to the limitations of the Freedom of 
Information Act (FOIA) (5 U.S.C. 552), the regulations contained in 43 
CFR part 2 (Records and Testimony).
    (b) BOEM will not release such data and information that we have 
determined is exempt from disclosure under exemption 4 of FOIA. We will 
review such data and information and objections of the submitter by the 
following schedule to determine whether release at that time will 
result in substantial competitive harm or disclosure of trade secrets.

------------------------------------------------------------------------
                                          Then BOEM will review data and
          If you have a . . .                information for possible
                                                     release:
------------------------------------------------------------------------
(1) Commercial lease...................  At the earlier of:
                                            (i) 3 years after the
                                             initiation of commercial
                                             generation or
                                            (ii) 3 years after the lease
                                             terminates.
(2) Limited lease......................  At 3 years after the lease
                                          terminates.
(3) ROW or RUE grant...................  At the earliest of:
                                            (i) 10 years after the
                                             approval of the grant;
                                            (ii) Grant termination; or
                                            (iii) 3 years after the
                                             completion of construction
                                             activities.
------------------------------------------------------------------------

     (c) After considering any objections from the submitter, if we 
determine that release of such data and information will result in:
    (1) No substantial competitive harm or disclosure of trade secrets, 
then the data and information will be released.
    (2) Substantial competitive harm or disclosure of trade secrets, 
then the data and information will not be released at that time but 
will be subject to further review every 3 years thereafter.

Sec.  585.114  Paperwork Reduction Act statements--information 
collection.

    (a) The Office of Management and Budget (OMB) has approved the 
information collection requirements in 30 CFR part 585 under 44 U.S.C. 
3501, et seq., and assigned OMB Control Number 1010-0176. The table in 
paragraph (e) of this section lists the subpart in the rule requiring 
the information and its title, summarizes the reasons for collecting 
the information, and summarizes how BOEM uses the information.
    (b) Respondents are primarily renewable energy applicants, lessees, 
ROW grant holders, RUE grant holders, Alternate Use RUE grant holders, 
and operators. The requirement to respond to the information collection 
in this part is mandated under subsection 8(p) of the OCS Lands Act. 
Some responses are also required to obtain or retain a benefit, or may 
be voluntary.
    (c) The Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq.) 
requires us to inform the public that an agency may not conduct or 
sponsor, and you are not required to respond to, a collection of 
information unless it displays a currently valid OMB control number.
    (d) Comments regarding any aspect of the collections of information 
under this part, including suggestions for reducing the burden should 
be sent to the Information Collection Clearance Officer, Bureau of 
Ocean Energy Management, 381 Elden Street, Herndon, VA 20170.
    (e) BOEM is collecting this information for the reasons given in 
the following table:

------------------------------------------------------------------------
 30 CFR 585 subpart, title, and/or BOEM       Reasons for collecting
         Form (OMB Control No.)              information and how used
------------------------------------------------------------------------
(1) Subpart A--General Provisions......  To inform BOEM of actions taken
                                          to comply with general
                                          operational requirements on
                                          the OCS. To ensure that
                                          operations on the OCS meet
                                          statutory and regulatory
                                          requirements, are safe and
                                          protect the environment, and
                                          result in diligent development
                                          on OCS leases.
(2) Subpart B--Issuance of OCS           To provide BOEM with
 Renewable Energy Leases.                 information needed to
                                          determine when to use a
                                          competitive process for
                                          issuing a renewable energy
                                          lease, to identify auction
                                          formats and bidding systems
                                          and variables that we may use
                                          when that determination is
                                          affirmative, and to determine
                                          the terms under which we will
                                          issue renewable energy leases.
(3) Subpart C--ROW Grants and RUE        To issue ROW grants and RUE
 Grants for Renewable Energy Activities.  grants for OCS renewable
                                          energy activities that are not
                                          associated with a BOEM-issued
                                          renewable energy lease.
(4) Subpart D--Lease and Grant           To ensure compliance with
 Administration.                          regulations pertaining to a
                                          lease or grant; assignment and
                                          designation of operator; and
                                          suspension, renewal,
                                          termination, relinquishment,
                                          and cancellation of leases and
                                          grants.
(5) Subpart E--Payments and Financial    To ensure that payments and
 Assurance Requirements.                  financial assurance payments
                                          for renewable energy leases
                                          comply with subpart E.
(6) Subpart F--Plans and Information     To enable BOEM to comply with
 Requirements.                            the National Environmental
                                          Policy Act (NEPA), the Coastal
                                          Zone Management Act (CZMA),
                                          and other Federal laws and to
                                          ensure the safety of the
                                          environment on the OCS.
(7) Subpart G--Facility Design,          To enable BOEM to review the
 Fabrication, and Installation.           final design, fabrication, and
                                          installation of facilities on
                                          a lease or grant to ensure
                                          that these facilities are
                                          designed, fabricated, and
                                          installed according to
                                          appropriate standards in
                                          compliance with BOEM
                                          regulations, and where
                                          applicable, the approved plan.

[[Page 64737]]

 
(8) Subpart H--Environmental and Safety  To ensure that lease and grant
 Management, Inspections, and Facility    operations are conducted in a
 Assessments.                             manner that is safe and
                                          protects the environment. To
                                          ensure compliance with other
                                          Federal laws, these
                                          regulations, the lease or
                                          grant, and approved plans.
(9) Subpart I--Decommissioning.........  To determine that
                                          decommissioning activities
                                          comply with regulatory
                                          requirements and approvals. To
                                          ensure that site clearance and
                                          platform or pipeline removal
                                          are properly performed to
                                          protect marine life and the
                                          environment and do not
                                          conflict with other users of
                                          the OCS.
(10) Subpart J--RUEs for Energy and      To enable BOEM to review
 Marine-Related Activities Using          information regarding the
 Existing OCS Facilities.                 design, installation, and
                                          operation of RUEs on the OCS,
                                          to ensure that RUE operations
                                          are safe and protect the
                                          human, marine, and coastal
                                          environment. To ensure
                                          compliance with other Federal
                                          laws, these regulations, the
                                          RUE grant, and, where
                                          applicable, the approved plan.
------------------------------------------------------------------------

Sec.  585.115  Documents incorporated by reference.

    (a) BOEM is incorporating by reference the documents listed in the 
table in paragraph (e) of this section. The Director of the Federal 
Register has approved this incorporation by reference according to 5 
U.S.C. 552(a) and 1 CFR part 51.
    (1) BOEM will publish, as a rule, any changes in the documents 
incorporated by reference in the Federal Register.
    (2) BOEM may amend by rule the list of industry standards 
incorporated by reference of the document effective without prior 
opportunity for public comment when BOEM determines that the revisions 
to a document result in safety improvements or represent new industry 
standard technology and do not impose undue costs on the affected 
parties; and
    (3) BOEM may make a rule, effective immediately, amending the list 
of industry standards incorporated by reference if it determines good 
cause exists for doing so under 5 U.S.C. 553.
    (b) BOEM is incorporating each document or specific portion by 
reference in the sections noted. The entire document is incorporated by 
reference, unless the text of the corresponding sections in this part 
calls for compliance with specific portions of the listed documents. In 
each instance, the applicable document is the specific edition, or 
specific edition and supplement, or specific addition and addendum 
cited in this section.
    (c) You may comply with a later edition of a specific document 
incorporated by reference, only if:
    (1) You show that complying with the later edition provides a 
degree of protection, safety, or performance equal to or better than 
what would be achieved by compliance with the listed edition; and
    (2) You obtain the prior written approval for alternative 
compliance from the authorized BOEM official.
    (d) You may inspect these documents at the Bureau of Ocean Energy 
Management, 381 Elden Street, Room 3313, Herndon, Virginia, 703-787-
1605; or at the National Archives and Records Administration (NARA). 
For information on the availability of this material at NARA, call 202-
741-6030, or go to: http://www.archives.gov/federal_register/code_of_federal_regulations/ibr_locations.html. You may obtain the 
documents from the publishing organizations at the addresses given in 
the following table:

------------------------------------------------------------------------
               For . . .                          Write to . . .
------------------------------------------------------------------------
API Recommended Practices..............  American Petroleum Institute,
                                          1220 L Street, NW.,
                                          Washington, DC 20005-4070.
                                          http://www.api.org/publications/ publications/
------------------------------------------------------------------------

     (e) This paragraph lists documents incorporated by reference. To 
easily reference text of the corresponding sections with the list of 
documents incorporated by reference, the list is in alphanumerical 
order by organization and document.

----------------------------------------------------------------------------------------------------------------
                 Title of documents                               Incorporated by reference at . . .
----------------------------------------------------------------------------------------------------------------
API RP 2A-WSD, Recommended Practice for Planning,     30 CFR 585.825
 Designing and Constructing Fixed Offshore
 Platforms--Working Stress Design; Twenty-first
 Edition, December 2000; Errata and Supplement 1,
 December 2002; Errata and Supplement 2, September
 2005; Errata and Supplement 3, October 2007;
 Product No. G2AWSD.
----------------------------------------------------------------------------------------------------------------

Sec.  585.116  Requests for information on the state of the offshore 
renewable energy industry.

    (a) The Director may, from time to time, and at his discretion, 
solicit information from industry and other relevant stakeholders 
(including State and local agencies), as necessary, to evaluate the 
state of the offshore renewable energy industry, including the 
identification of potential challenges or obstacles to its continued 
development. Such requests for information may relate to the 
identification of environmental, technical, regulatory, or economic 
matters that promote or detract from continued development of renewable 
energy technologies on the OCS. From the information received, the 
Director may evaluate potential refinements to the OCS Alternative 
Energy Program that promote development of the industry in a safe and 
environmentally responsible manner, and that ensure fair value for use 
of the Nation's OCS.
    (b) BOEM may make such requests for information on a regional 
basis, and may tailor the requests to specific types of renewable 
energy technologies.
    (c) BOEM will publish such requests for information by the Director 
in the Federal Register.

[[Page 64738]]

Sec.  585.117  [Reserved]

Sec.  585.118  What are my appeal rights?

    (a) Any party adversely affected by a BOEM official's final 
decision or order issued under the regulations of this part may appeal 
that decision or order to the Interior Board of Land Appeals. The 
appeal must conform with the procedures found in 30 CFR part 590 and 43 
CFR part 4, subpart E. Appeal of a final decision for bid acceptance is 
covered under paragraph (c) of this section.
    (b) A decision will remain in full force and effect during the 
period in which an appeal may be filed and during an appeal, unless a 
stay is granted pursuant to 43 CFR part 4.
    (c) Our decision on a bid is the final action of the Department, 
except that an unsuccessful bidder may apply for reconsideration by the 
Director.
    (1) A bidder whose bid we reject may file a written request for 
reconsideration with the Director within 15 days of the date of the 
receipt of the notice of rejection, accompanied by a statement of 
reasons, with one copy to us. The Director will respond in writing 
either affirming or reversing the decision.
    (2) The delegation of review authority given to the Office of 
Hearings and Appeals does not apply to decisions on high bids for 
leases or grants under this part.

Subpart B--Issuance of OCS Renewable Energy Leases

General Lease Information

Sec.  585.200  What rights are granted with a lease issued under this 
part?

    (a) A lease issued under this part grants the lessee the right, 
subject to obtaining the necessary approvals, including but not limited 
to those required under the FERC hydrokinetic licensing process, and 
complying with all provisions of this part, to occupy, and install and 
operate facilities on, a designated portion of the OCS for the purpose 
of conducting:
    (1) Commercial activities; or
    (2) Other limited activities that support, result from, or relate 
to the production of energy from a renewable energy source.
    (b) A lease issued under this part confers on the lessee the right 
to one or more project easements without further competition for the 
purpose of installing gathering, transmission, and distribution cables; 
pipelines; and appurtenances on the OCS as necessary for the full 
enjoyment of the lease.
    (1) You must apply for the project easement as part of your COP or 
GAP, as provided under subpart F of this part; and
    (2) BOEM will incorporate your approved project easement in your 
lease as an addendum.
    (c) A commercial lease issued under this part may be developed in 
phases, with BOEM approval as provided in Sec.  585.629.

Sec.  585.201  How will BOEM issue leases?

    BOEM will issue leases on a competitive basis, as provided under 
Sec. Sec.  585.210 through 585.225. However, if we determine after 
public notice of a proposed lease that there is no competitive 
interest, we will issue leases noncompetitively, as provided under 
Sec. Sec.  585.230 and 585.232. We will issue leases on forms approved 
by BOEM and will include terms, conditions, and stipulations identified 
and developed through the process set forth in Sec. Sec.  585.211 and 
585.231.

Sec.  585.202  What types of leases will BOEM issue?

    BOEM may issue leases on the OCS for the assessment and production 
of renewable energy and may authorize a combination of specific 
activities. We may issue commercial leases or limited leases.

Sec.  585.203  With whom will BOEM consult before issuance of a lease?

    For leases issued under this part, through either the competitive 
or noncompetitive process, BOEM prior to issuing the lease, will 
coordinate and consult with relevant Federal agencies (including, in 
particular, those agencies involved in planning activities that are 
undertaken to avoid conflicts among users and maximize the economic and 
ecological benefits of the OCS, including multifaceted spatial planning 
efforts), the Governor of any affected State, the executive of any 
affected local government, and any affected Indian Tribe, as directed 
by subsections 8(p)(4) and (7) of the OCS Lands Act or other relevant 
Federal laws. Federal statutes that require us to consult with or 
respond to findings include the Endangered Species Act (ESA), and the 
Magnuson-Stevens Fishery Conservation and Management Act (MSA).

Sec.  585.204  What areas are available for leasing consideration?

    BOEM may offer any appropriately platted area of the OCS, as 
provided in Sec.  585.205, for a renewable energy lease, except any 
area within the exterior boundaries of any unit of the National Park 
System, National Wildlife Refuge System, National Marine Sanctuary 
System, or any National Monument.

Sec.  585.205  How will leases be mapped?

    BOEM will prepare leasing maps and official protraction diagrams of 
areas of the OCS. The areas included in each lease will be in 
accordance with the appropriate leasing map or official protraction 
diagram.

Sec.  585.206  What is the lease size?

    (a) BOEM will determine the size for each lease based on the area 
required to accommodate the anticipated activities. The processes 
leading to both competitive and noncompetitive issuance of leases will 
provide public notice of the lease size adopted. We will delineate 
leases by using mapped OCS blocks or portions, or aggregations of 
blocks.
    (b) The lease size includes the minimum area that will allow the 
lessee sufficient space to develop the project and manage activities in 
a manner that is consistent with the provisions of this part. The lease 
may include whole lease blocks or portions of a lease block.

Sec. Sec.  585.207-585.209  [Reserved]

Competitive Lease Process

Sec.  585.210  How does BOEM initiate the competitive leasing process?

    BOEM may publish in the Federal Register a public notice of Request 
for Interest to assess interest in leasing all or part of the OCS for 
activities authorized in this part. BOEM will consider information 
received in response to a Request for Interest to determine whether 
there is competitive interest for scheduling sales and issuing leases. 
We may prepare and issue a national, regional, or more specific 
schedule of lease sales pertaining to one or more types of renewable 
energy.

Sec.  585.211  What is the process for competitive issuance of leases?

    BOEM will use auctions to award leases on a competitive basis. We 
will publish details of the process to be employed for each lease sale 
auction in the Federal Register. For each lease sale, we will publish a 
Proposed Sale Notice and a Final Sale Notice. Individual lease sales 
will include steps such as:
    (a) Call for Information and Nominations (Call). BOEM will publish 
in the Federal Register Calls for Information and Nominations for 
leasing in specified areas. The comment period following issuance of a 
Call will be 45 days. In this document, we may:
    (1) Request comments on areas which should receive special 
consideration and analysis;
    (2) Request comments concerning geological conditions (including 
bottom

[[Page 64739]]

hazards); archaeological sites on the seabed or nearshore; multiple 
uses of the proposed leasing area (including navigation, recreation, 
and fisheries); and other socioeconomic, biological, and environmental 
information; and
    (3) Suggest areas to be considered by the respondents for leasing.
    (b) Area Identification. BOEM will identify areas for environmental 
analysis and consideration for leasing. We will do this in consultation 
with appropriate Federal agencies, States, local governments, affected 
Indian Tribes, and other interested parties.
    (1) We may consider for lease those areas nominated in response to 
the Call for Information and Nominations, together with other areas 
that BOEM determines are appropriate for leasing.
    (2) We will evaluate the potential effect of leasing on the human, 
marine, and coastal environments, and develop measures to mitigate 
adverse impacts, including lease stipulations.
    (3) We will consult to develop measures, including lease 
stipulations and conditions, to mitigate adverse impacts on the 
environment; and
    (4) We may hold public hearings on the environmental analysis after 
appropriate notice.
    (c) Proposed Sale Notice. BOEM will publish the Proposed Sale 
Notice in the Federal Register and send it to the Governor of any 
affected State and the executive of any local government that might be 
affected. The comment period following issuance of a Proposed Sale 
Notice will be 60 days.
    (d) Final Sale Notice. BOEM will publish the Final Sale Notice in 
the Federal Register at least 30 days before the date of the sale.

Sec.  585.212  What is the process BOEM will follow if there is reason 
to believe that competitors have withdrawn before the Final Sale Notice 
is issued?

    BOEM may decide to end the competitive process before the Final 
Sale Notice if we have reason to believe that competitors have 
withdrawn and competition no longer exists. We will issue a second 
public notice of Request for Interest and consider comments received to 
confirm that there is no competitive interest.
    (a) If, after reviewing comments in response to the notice of 
Request for Interest, BOEM determines that there is no competitive 
interest in the lease area, and one party wishes to acquire a lease, we 
will discontinue the competitive process and will proceed with the 
noncompetitive process set forth in Sec.  585.231(d) through (i). Under 
the noncompetitive process, the acquisition fee specified in Sec.  
585.502(a) must be submitted with the Site Assessment Plan (SAP) or 
General Activities Plan (GAP).
    (b) If, after reviewing comments in response to the notice of 
Request for Interest, BOEM determines that competitive interest in the 
lease area continues to exist, we will continue with the competitive 
process set forth in Sec. Sec.  585.211 through 585.225.

Sec.  585.213  What must I submit in response to a Request for Interest 
or a Call for Information and Nominations?

    If you are a potential lessee, when you respond to a Request for 
Interest or a Call, your response must include the following items:
    (a) The area of interest for a possible lease.
    (b) A general description of your objectives and the facilities 
that you would use to achieve those objectives.
    (c) A general schedule of proposed activities, including those 
leading to commercial operations.
    (d) Available and pertinent data and information concerning 
renewable energy and environmental conditions in the area of interest, 
including energy and resource data and information used to evaluate the 
area of interest. BOEM will withhold trade secrets and commercial or 
financial information that is privileged or confidential from public 
disclosure under exemption 4 of the FOIA and as provided in Sec.  
585.113.
    (e) Documentation showing that you are qualified to hold a lease, 
as specified in Sec.  585.107.
    (f) Any other information requested by BOEM in the Federal Register 
notice.

Sec.  585.214  What will BOEM do with information from the Requests for 
Information or Calls for Information and Nominations?

    BOEM will use the information received in response to the Requests 
or Calls to:
    (a) Identify the lease area;
    (b) Develop options for the environmental analysis and leasing 
provisions (stipulations, payments, terms, and conditions); and
    (c) Prepare appropriate documentation to satisfy applicable Federal 
requirements, such as NEPA, CZMA, the ESA, and the MMPA.

Sec.  585.215  What areas will BOEM offer in a lease sale?

    BOEM will offer the areas for leasing determined through the 
process set forth in Sec.  585.211 of this part. We will not accept 
nominations after the Call for Information and Nominations closes.

Sec.  585.216  What information will BOEM publish in the Proposed Sale 
Notice and Final Sale Notice?

    For each competitive lease sale, BOEM will publish a Proposed Sale 
Notice and a Final Sale Notice in the Federal Register. In the Proposed 
Sale Notice, we will request public comment on the items listed in this 
section. We will consider all public comments received in developing 
the final lease sale terms and conditions. We will publish the final 
terms and conditions in the Final Sale Notice. The Proposed Sale Notice 
and Final Sale Notice will include, or describe the availability of, 
information pertaining to:
    (a) The area available for leasing.
    (b) Proposed and final lease provisions and conditions, including, 
but not limited to:
    (1) Lease size;
    (2) Lease term;
    (3) Payment requirements;
    (4) Performance requirements; and
    (5) Site-specific lease stipulations.
    (c) Auction details, including:
    (1) Bidding procedures and systems;
    (2) Minimum bid;
    (3) Deposit amount;
    (4) The place and time for filing bids and the place, date, and 
hour for opening bids;
    (5) Lease award method; and
    (6) Bidding or application instructions.
    (d) The official BOEM lease form to be used or a reference to that 
form.
    (e) Criteria BOEM will use to evaluate competing bids or 
applications and how the criteria will be used in decision-making for 
awarding a lease.
    (f) Award procedures, including how and when BOEM will award leases 
and how BOEM will handle unsuccessful bids or applications.
    (g) Procedures for appealing the lease issuance decision.
    (h) Execution of the lease instrument.

Sec. Sec.  585.217-585.219  [Reserved]

Competitive Lease Award Process

Sec.  585.220  What auction format may BOEM use in a lease sale?

    (a) Except as provided in Sec.  585.231, we will hold competitive 
auctions to award renewable energy leases and will use one of the 
following auction formats, as determined through the lease sale process 
and specified in the Proposed Sale Notice and in the Final Sale Notice:

[[Page 64740]]

------------------------------------------------------------------------
       Type of auction            Bid variable         Bidding process
------------------------------------------------------------------------
(1) Sealed bidding..........  A cash bonus or an    One sealed bid per
                               operating fee rate.   company per lease
                                                     or packaged bidding
                                                     unit.
(2) Ascending bidding.......  A cash bonus or an    Continuous bidding
                               operating fee rate.   per lease.
(3) Two-stage bidding         An operating fee      Ascending or sealed
 (combination of ascending     rate in one, both,    bidding until:
 and sealed bidding).          or neither stage     (i) Only two bidders
                               and a cash bonus in   remain, or
                               one, both, or        (ii) More than one
                               neither stage.        bidder offers to
                                                     pay the maximum bid
                                                     amount.
                                                    Stage-two sealed or
                                                     ascending bidding
                                                     commences at some
                                                     predetermined time
                                                     after the end of
                                                     stage-one bidding.
(4) Multiple-factor bidding.  Factors may include,  One proposal per
                               but are not limited   company per lease
                               to: technical         or packaged bidding
                               merit, timeliness,    unit.
                               financing and
                               economics,
                               environmental
                               considerations,
                               public benefits,
                               compatibility with
                               State and local
                               needs, cash bonus,
                               rental rate, and an
                               operating fee rate.
------------------------------------------------------------------------

     (b) You must submit your bid and a deposit as specified in 
Sec. Sec.  585.500 and 585.501 to cover the bid for each lease area, 
according to the terms specified in the Final Sale Notice.

Sec.  585.221  What bidding systems may BOEM use for commercial leases 
and limited leases?

    (a) For commercial leases, we will specify minimum bids in the 
Final Sale Notice and use one of the following bidding systems, as 
specified in the Proposed Sale Notice and in the Final Sale Notice:

------------------------------------------------------------------------
               Bid system                          Bid variable
------------------------------------------------------------------------
(1) Cash bonus with a constant fee rate  Cash bonus.
 (decimal).
(2) Constant operating fee rate with     A fee rate used in the formula
 fixed cash bonus.                        found in Sec.   585.506 to set
                                          the operating fee per year
                                          during the operations term of
                                          your lease.
(3) Sliding operating fee rate with a    A fee rate used in the formula
 fixed cash bonus.                        in Sec.   585.506 to set the
                                          operating fee for the first
                                          year of the operations term of
                                          your lease. The fee rate for
                                          subsequent years changes by a
                                          mathematical function we
                                          specify in the Final Sale
                                          Notice.
(4) Cash bonus and constant operating    Cash bonus and operating fee
 fee rate.                                rate as stated in paragraph
                                          (2) of this section (two-stage
                                          auction format only).
(5) Cash bonus and sliding operating     Cash bonus and operating fee
 fee rate.                                rate as stated in paragraph
                                          (3) of this section (two-stage
                                          auction format only).
(6) Multiple-factor combination of       BOEM will identify bidding
 nonmonetary and monetary factors.        variables in the Final Sale
                                          Notice.
                                         Variables may include:
                                         (i) Nonmonetary (e.g.,
                                          technical merit) factors and
                                         (ii) Monetary (e.g., cash
                                          bonus, rental rate, fee rate)
                                          factors.
------------------------------------------------------------------------

     (b) For limited leases, the bid variable will be a cash bonus, 
with a minimum bid as we specify in the Final Sale Notice.

Sec.  585.222  What does BOEM do with my bid?

    (a) If sealed bidding is used:
    (1) We open the sealed bids at the place, date, and hour specified 
in the Final Sale Notice for the sole purpose of publicly announcing 
and recording the bids. We do not accept or reject any bids at that 
time.
    (2) We reserve the right to reject any and all high bids, including 
a bid for any proposal submitted under the multiple-factor bidding 
format, regardless of the amount offered or bidding system used. The 
reasons for the rejection of a winning bid may include, but are not 
necessarily limited to, insufficiency, illegality, anti-competitive 
behavior, administrative error, and the presence of unusual bidding 
patterns. We intend to accept or reject all high bids within 90 days, 
but we may extend that time if necessary.
    (b) If we use ascending bidding, we may, in the Final Sale Notice, 
reserve the right to accept the winning bid solely based on its being 
the highest bid submitted by a qualified bidder (qualified to be an OCS 
lessee under Sec.  585.107).
    (c) If we use two-stage bidding and the auction concludes with
    (i) An ascending bidding stage, the winning bid will be determined 
as stated in paragraph (b) of this section; or
    (ii) A sealed bidding stage, the winning bid will be determined as 
stated in paragraph (a) of this section.
    (d) If we use multiple-factor bidding, determination of the winning 
bid for any proposal submitted will be made by a panel composed of 
members selected by BOEM. The details of the process will be described 
in the Final Sale Notice.
    (e) We will send a written notice of our decision to accept or 
reject bids to all bidders whose deposits we hold.

Sec.  585.223  What does BOEM do if there is a tie for the highest bid?

    (a) Unless otherwise specified in the Final Sale Notice, except in 
the first stage of a two-stage bidding auction, if more than one bidder 
on a lease submits the same high bid amount, the winning bidder will be 
determined by a further round or stage of bidding as described in the 
Final Sale Notice.
    (b) The winning bidder will be subject to final confirmation 
following determination of bid adequacy.

Sec.  585.224  What happens if BOEM accepts my bid?

    If we accept your bid, we will send you a notice with three copies 
of the lease form.
    (a) Within 10 business days after you receive the lease copies, you 
must:
    (1) Execute the lease;

[[Page 64741]]

    (2) File financial assurance as required under Sec. Sec.  585.515 
through 585.537; and
    (3) Pay the balance of the bonus bid as specified in the lease sale 
notice.
    (b) Within 45 days after you receive the lease copies, you must pay 
the first 6 months rent as required in Sec.  585.503.
    (c) When you execute three copies of the lease and return the 
copies to us, we will execute the lease on behalf of the United States 
and send you one fully executed copy.
    (d) You will forfeit your deposit if you do not execute and return 
the lease within 10 business days of receipt, or otherwise fail to 
comply with applicable regulations or terms of the Final Sale Notice.
    (e) We may extend the 10 business day time period for executing and 
returning the lease if we determine the delay to be caused by events 
beyond your control.
    (f) We reserve the right to withdraw an OCS area in which we have 
held a lease sale before you and BOEM execute the lease in that area. 
If we exercise this right, we will refund your bid deposit, without 
interest.
    (g) If the awarded lease is executed by an agent acting on behalf 
of the bidder, the bidder must submit, along with the executed lease, 
written evidence that the agent is authorized to act on behalf of the 
bidder.
    (h) BOEM will consider the highest submitted qualified bid to be 
the winning bid when bidding occurs under the systems described in 
Sec.  585.221(a)(1) through (5). We will determine the winning bid for 
proposals submitted under the multiple-factor bidding format on the 
basis of selection by the panel as specified in Sec.  585.222(d) when 
the bidding system under Sec.  585.221(a)(6) is used. We will refund 
the deposit on all other bids.

Sec.  585.225  What happens if my bid is rejected, and what are my 
appeal rights?

    (a) If we reject your bid, we will provide a written statement of 
the reasons and refund any money deposited with your bid, without 
interest.
    (b) You may ask the BOEM Director for reconsideration, in writing, 
within 15 business days of bid rejection, under Sec.  585.118(c)(1). We 
will send you a written response either affirming or reversing the 
rejection.

Sec. Sec.  585.226-585.229  [Reserved]

Noncompetitive Lease Award Process

Sec.  585.230  May I request a lease if there is no Call?

    You may submit an unsolicited request for a commercial lease or a 
limited lease under this part. Your unsolicited request must contain 
the following information:
    (a) The area you are requesting for lease.
    (b) A general description of your objectives and the facilities 
that you would use to achieve those objectives.
    (c) A general schedule of proposed activities including those 
leading to commercial operations.
    (d) Available and pertinent data and information concerning 
renewable energy and environmental conditions in the area of interest, 
including energy and resource data and information used to evaluate the 
area of interest. BOEM will withhold trade secrets and commercial or 
financial information that is privileged or confidential from public 
disclosure under exemption 4 of the FOIA and as provided in Sec.  
585.113.
    (e) If available from the appropriate State or local government 
authority, a statement that the proposed activity conforms with State 
and local energy planning requirements, initiatives, or guidance.
    (f) Documentation showing that you meet the qualifications to 
become a lessee, as specified in Sec.  585.107.
    (g) An acquisition fee, as specified in Sec.  585.502(a).

Sec.  585.231  How will BOEM process my unsolicited request for a 
noncompetitive lease?

    (a) BOEM will consider unsolicited requests for a lease on a case-
by-case basis and may issue a lease noncompetitively in accordance with 
this part. We will not consider an unsolicited request for a lease 
under this part that is proposed in an area of the OCS that is 
scheduled for a lease sale under this part.
    (b) BOEM will issue a public notice of a request for interest 
relating to your proposal and consider comments received to determine 
if competitive interest exists.
    (c) If BOEM determines that competitive interest exists in the 
lease area:
    (1) BOEM will proceed with the competitive process set forth in 
Sec. Sec.  585.210 through 585.225;
    (2) If you submit a bid for the lease area in a competitive lease 
sale, your acquisition fee will be applied to the deposit for your 
bonus bid; and
    (3) If you do not submit a bid for the lease area in a competitive 
lease sale, BOEM will not refund your acquisition fee.
    (d) If BOEM determines that there is no competitive interest in a 
lease:
    (1) We will publish a notice, in the Federal Register, of such 
determination; and
    (2) You must submit within 60 days of the date of the notice to 
BOEM:
    (i) For a commercial lease, a SAP, as described in Sec. Sec.  
585.605 through 585.613; or
    (ii) For a limited lease, a GAP, as described in Sec. Sec.  585.640 
through 585.648.
    (e) BOEM will coordinate and consult with affected Federal 
agencies, State, and local governments, and affected Indian Tribes in 
the review of noncompetitive lease requests and associated plans.
    (f) If we approve or approve with conditions your SAP or GAP, we 
may offer you a noncompetitive lease.
    (g) If you accept the terms and conditions of the lease, then we 
will issue the lease, and you must comply with all terms and conditions 
of your lease and all applicable provisions of this part. If we issue 
you a lease, we will send you a notice with 3 copies of the lease form.
    (1) Within 10 business days after you receive the lease copies you 
must:
    (i) Execute the lease;
    (ii) File financial assurance as required under Sec. Sec.  585.515 
through 585.537; and
    (2) Within 45 days after you receive the lease copies, you must pay 
the first 6 months rent, as required in Sec.  585.503.
    (h) BOEM will publish in the Federal Register a notice announcing 
the issuance of your lease.
    (i) If you do not accept the terms and conditions, BOEM will not 
issue a lease, and we will not refund your acquisition fee.

Sec.  585.232  May I acquire a lease noncompetitively after responding 
to a Request for Interest or Call for Information and Nominations?

    (a) If you submit an area of interest for a possible lease and BOEM 
receives no competing submissions in response to the RFI or Call, we 
may inform you that there does not appear to be competitive interest, 
and ask if you wish to proceed with acquiring a lease.
    (b) If you wish to proceed with acquiring a lease, you must submit 
your acquisition fee as specified in Sec.  585.502(a).
    (c) After receiving the acquisition fee, BOEM will follow the 
process outlined in Sec.  585.231(b) through (i).

Sec.  585.233  [Reserved]

Sec.  585.234  [Reserved]

Commercial and Limited Lease Terms

Sec.  585.235  If I have a commercial lease, how long will my lease 
remain in effect?

    (a) For commercial leases, the lease terms and applicable automatic

[[Page 64742]]

extensions are as shown in the following table:

------------------------------------------------------------------------
         Lease term           Automatic extensions      Requirements
------------------------------------------------------------------------
(1) Each commercial lease     If we receive a SAP   The SAP must meet
 issued competitively will     that satisfies the    the requirements of
 have a preliminary term of    requirements of       Sec.  Sec.
 6 months to submit:           Sec.  Sec.            585.605 through
 (i) a SAP; or..............   585.605 through       585.613. The SAP/
(ii) a combined SAP and COP.   585.613 or a SAP/     COP must meet the
 The preliminary term begins   COP that satisfies    requirements of
 on the effective date of      the requirements of   Sec.  Sec.
 the lease. A commercial       Sec.  Sec.            585.605 through
 lease issued                  585.605 through       585.613 and Sec.
 noncompetitively does not     585.613 and Sec.      Sec.   585.620
 have a preliminary term..     Sec.   585.620        through 585.629.
                               through 585.629,
                               the preliminary
                               term will be
                               extended for the
                               time necessary for
                               us to conduct
                               technical and
                               environmental
                               reviews of the SAP
                               or SAP/COP.
(2) A commercial lease will   If we receive a COP   The COP must meet
 have a site assessment term   that satisfies the    the requirements of
 of 5 years to conduct site    requirements of       Sec.  Sec.
 assessment activities and     Sec.  Sec.            585.620 through
 to submit a COP, if a SAP/    585.620 through       585.629 of this
 COP has not been submitted.   585.629, the site     part.
 Your site assessment term     assessment term
 begins when BOEM approves     will be
 your SAP or SAP/COP.          automatically
                               extended for the
                               period of time
                               necessary for us to
                               conduct technical
                               and environmental
                               reviews of the COP.
(3) A commercial lease will   ....................  The lease renewal
 have an operations term of                          request must meet
 25 years, unless a longer                           the requirements,
 term is negotiated by                               as provided in Sec.
 applicable parties.                                  Sec.   585.425
A request for lease renewal                          through 585.429.
 must be submitted 2 years
 before the end of the
 operations term..
If you submit a COP, your
 operations term begins on
 the date that we approve
 the COP. If you submit a
 SAP/COP, your operations
 term begins 5 years after
 the date we approve the SAP/
 COP, or when fabrication
 and installation commence,
 whichever is earlier.
(4) A commercial lease may    ....................  We may order or
 have additional time added                          grant a suspension
 to the operations term                              of the operations
 through a lease renewal.                            term, as provided
 The term of the lease                               in Sec.  Sec.
 renewal will not exceed the                         585.415 through
 original term of the lease,                         585.421.
 unless a longer term is
 negotiated by applicable
 parties. The lease renewal
 term begins upon expiration
 of the original operations
 term.
------------------------------------------------------------------------

    (b) If you do not timely submit a SAP, COP, or SAP/COP, as 
appropriate, you may request additional time to extend the preliminary 
or site assessment term of your commercial lease that includes a 
revised schedule for submission of the plan, as appropriate.

Sec.  585.236  If I have a limited lease, how long will my lease remain 
in effect?

    (a) For limited leases, the lease terms are as shown in the 
following table:

------------------------------------------------------------------------
                                  Extension or
         Lease term                suspension           Requirements
------------------------------------------------------------------------
(1) Each limited lease        If we receive a GAP   The GAP must meet
 issued competitively has a    that satisfies the    the requirements of
 preliminary term of 6         requirements of       Sec.  Sec.
 months to submit a GAP. The   Sec.  Sec.            585.640 through
 preliminary term begins on    585.640 through       585.648.
 the effective date of the     585.648 of this
 lease.                        part, the
                               preliminary term
                               will be
                               automatically
                               extended for the
                               period of time
                               necessary for us to
                               conduct a technical
                               and environmental
                               review of the plans.
(2) The operations term       ....................  You must submit and
 begins when BOEM approves                           BOEM must approve
 your GAP and issues your                            your GAP before we
 lease. A limited lease                              will issue a lease.
 issued noncompetitively                             The GAP must meet
 does not have a preliminary                         the requirements of
 term.                                               Sec.  Sec.
                                                     585.640 through
                                                     585.648.
(3) Each limited lease has    We may order or       ....................
 an operations term of 5       grant a suspension
 years for conducting site     of the operations
 assessment, technology        term as provided in
 testing, or other             Sec.  Sec.
 activities. The operations    585.415 through
 term begins on the date       585.421.
 that we approve your GAP.
------------------------------------------------------------------------

     (b) If you do not timely submit a GAP, you may request additional 
time to extend the preliminary term of your limited lease that includes 
a revised schedule for submission of a GAP.

Sec.  585.237  What is the effective date of a lease?

    (a) A lease issued under this part must be dated and becomes 
effective as of the first day of the month following the date a lease 
is signed by the lessor.
    (b) If the lessee submits a written request and BOEM approves, a 
lease may be dated and become effective the first day of the month in 
which it is signed by the lessor.

[[Page 64743]]

Sec.  585.238  Are there any other renewable energy research activities 
that will be allowed on the OCS?

    (a) The Director may issue OCS leases, ROW grants, and RUE grants 
to a Federal agency or a State for renewable energy research activities 
that support the future production, transportation, or transmission of 
renewable energy.
    (b) In issuing leases, ROW grants, and RUE grants to a Federal 
agency or a State on the OCS for renewable energy research activities 
under this provision, BOEM will coordinate and consult with other 
relevant Federal agencies, any other affected State(s), affected local 
government executives, and affected Indian Tribes.
    (c) BOEM may issue leases, RUEs, and ROWs for research activities 
managed by a Federal agency or a State only in areas for which the 
Director has determined, after public notice and opportunity to 
comment, that no competitive interest exists.
    (d) The Director and the head of the Federal agency or the Governor 
of a requesting State, or their authorized representatives, will 
negotiate the terms and conditions of such renewable energy leases, 
RUEs, or ROWs under this provision on a case-by-case basis. The 
framework for such negotiations, and standard terms and conditions of 
such leases, RUEs, or ROWs may be set forth in a memorandum of 
agreement (MOA) or other agreement between BOEM and a Federal agency or 
a State. The MOA must include the agreement of the head of the Federal 
agency or the Governor to assure that all subcontractors comply with 
these regulations, other applicable laws, and terms and conditions of 
such leases or grants.
    (e) Any lease, RUE, or ROW that BOEM issues to a Federal agency or 
to a State that authorizes access to an area of the OCS for research 
activities managed by a Federal agency or a State must include:
    (1) Requirements to comply with all applicable Federal laws; and
    (2) Requirements to comply with these regulations, except as 
otherwise provided in the lease or grant.
    (f) BOEM will issue a public notice of any lease, RUE, ROW issued 
to a Federal agency or to a State, or an approved MOA for such research 
activities.
    (g) BOEM will not charge any fees for the purpose of ensuring a 
fair return for the use of such research areas on the OCS.

Subpart C--Rights-of-Way Grants and Rights-of-Use and Easement 
Grants for Renewable Energy Activities

ROW Grants and RUE Grants

Sec.  585.300  What types of activities are authorized by ROW grants 
and RUE grants issued under this part?

    (a) An ROW grant authorizes the holder to install on the OCS 
cables, pipelines, and associated facilities that involve the 
transportation or transmission of electricity or other energy product 
from renewable energy projects.
    (b) An RUE grant authorizes the holder to construct and maintain 
facilities or other installations on the OCS that support the 
production, transportation, or transmission of electricity or other 
energy product from any renewable energy resource.
    (c) You do not need an ROW grant or RUE grant for a project 
easement authorized under Sec.  585.200(b) to serve your lease.

Sec.  585.301  What do ROW grants and RUE grants include?

    (a) An ROW grant:
    (1) Includes the full length of the corridor on which a cable, 
pipeline, or associated facility is located;
    (2) Is 200 feet (61 meters) in width, centered on the cable or 
pipeline, unless safety and environmental factors during construction 
and maintenance of the associated cable or pipeline require a greater 
width; and
    (3) For the associated facility, is limited to the area reasonably 
necessary for a power or pumping station or other accessory facility.
    (b) An RUE grant includes the site on which a facility or other 
structure is located and the areal extent of anchors, chains, and other 
equipment associated with a facility or other structure. The specific 
boundaries of an RUE will be determined by BOEM on a case-by-case basis 
and set forth in each RUE grant.

Sec.  585.302  What are the general requirements for ROW grant and RUE 
grant holders?

    (a) To acquire an ROW grant or RUE grant you must provide evidence 
that you meet the qualifications as required in Sec.  585.107.
    (b) An ROW grant or RUE grant is subject to the following 
conditions:
    (1) The rights granted will not prevent the granting of other 
rights by the United States, either before or after the granting of the 
ROW or RUE, provided that any subsequent authorization issued by BOEM 
in the area of a previously issued ROW grant or RUE grant may not 
unreasonably interfere with activities approved or impede existing 
operations under such a grant; and
    (2) The holder agrees that the United States, its lessees, or other 
ROW grant or RUE grant holders may use or occupy any part of the ROW 
grant or RUE grant not actually occupied or necessarily incident to its 
use for any necessary activities.

Sec.  585.303  How long will my ROW grant or RUE grant remain in 
effect?

    Your ROW grant or RUE grant will remain in effect for as long as 
the associated activities are properly maintained and used for the 
purpose for which the grant was made, unless otherwise expressly stated 
in the grant.

Sec.  585.304  [Reserved]

Obtaining ROW Grants and RUE Grants

Sec.  585.305  How do I request an ROW grant or RUE grant?

    You must submit to BOEM one paper copy and one electronic copy of a 
request for a new or modified ROW grant or RUE grant. You must submit a 
separate request for each ROW grant or RUE grant you are requesting. 
The request must contain the following information:
    (a) The area you are requesting for a ROW grant or RUE grant.
    (b) A general description of your objectives and the facilities 
that you would use to achieve those objectives.
    (c) A general schedule of proposed activities.
    (d) Pertinent information concerning environmental conditions in 
the area of interest.

Sec.  585.306  What action will BOEM take on my request?

    BOEM will consider requests for ROW grants and RUE grants on a 
case-by-case basis and may issue a grant competitively, as provided in 
Sec.  585.308, or noncompetitively if we determine after public notice 
that there is no competitive interest. BOEM will coordinate and consult 
with relevant Federal agencies, with the Governor of any affected 
State, and the executive of any affected local government.
    (a) In response to an unsolicited request for a ROW grant or RUE 
grant, the BOEM will first determine if there is competitive interest, 
as provided in Sec.  585.307.
    (b) If BOEM determines that there is no competitive interest in a 
ROW grant or RUE grant, we will:
    (1) In consultation with you, establish the terms and conditions 
for the grant;
    (2) Require you to submit a GAP, as described in Sec. Sec.  585.640 
through

[[Page 64744]]

585.648, within 60 days of the determination of no competitive 
interest; and
    (3) Evaluate your request for a noncompetitive grant and GAP 
simultaneously.
    (c) If we award your ROW grant or RUE grant competitively, you must 
submit and receive BOEM approval of your GAP, as provided in Sec. Sec.  
585.640 through 585.648.

Sec.  585.307  How will BOEM determine whether competitive interest 
exists for ROW grants and RUE grants?

    To determine whether or not there is competitive interest:
    (a) We will publish a public notice, describing the parameters of 
the project, to give affected and interested parties an opportunity to 
comment on the proposed ROW grant or RUE grant area.
    (b) We will evaluate any comments received on the notice and make a 
determination of the level of competitive interest.

Sec.  585.308  How will BOEM conduct an auction for ROW grants and RUE 
grants?

    (a) If BOEM determines that there is competitive interest, we will:
    (1) Publish a notice of each grant auction in the Federal Register 
describing auction procedures, allowing interested persons 30 days to 
comment; and
    (2) Conduct a competitive auction for issuing the ROW grant or RUE 
grant. The auction process for ROW grants and RUE grants will be 
conducted following the same process for leases set forth in Sec. Sec.  
585.211 through 585.225.
    (b) If you are the successful bidder in an auction, you must pay 
the first year's rent, as provided in Sec.  585.316.

Sec.  585.309  When will BOEM issue a noncompetitive ROW grant or RUE 
grant?

    If we approve or approve with conditions your GAP, we may offer you 
a noncompetitive grant.
    (a) If you accept the terms and conditions of the grant, then we 
will issue the grant, and you must comply with all terms and conditions 
of your grant and all applicable provisions of this part.
    (b) If you do not accept the terms and conditions, BOEM will not 
issue a grant.

Sec.  585.310  What is the effective date of an ROW grant or RUE grant?

    Your ROW grant or RUE grant becomes effective on the date 
established by BOEM on the ROW grant or RUE grant instrument.

Sec. Sec.  585.311-585.314  [Reserved]

Financial Requirements for ROW Grants and RUE Grants

Sec.  585.315  What deposits are required for a competitive ROW grant 
or RUE grant?

    (a) You must make a deposit, as required in Sec.  585.501(a), 
regardless of whether the auction is a sealed-bid, oral, electronic, or 
other auction format. BOEM will specify in the sale notice the official 
to whom you must submit the payment, the time by which the official 
must receive the payment, and the forms of acceptable payment.
    (b) If your high bid is rejected, we will provide a written 
statement of reasons.
    (c) For all rejected bids, we will refund, without interest, any 
money deposited with your bid.

Sec.  585.316  What payments are required for ROW grants or RUE grants?

    Before we issue the ROW grant or RUE grant, you must pay:
    (a) Any balance on accepted high bids to BOEM, as provided in the 
sale notice.
    (b) An annual rent for the first year of the grant, as specified in 
Sec.  585.508.

Subpart D--Lease and Grant Administration

Noncompliance and Cessation Orders

Sec.  585.400  What happens if I fail to comply with this part?

    (a) BOEM may take appropriate corrective action under this part if 
you fail to comply with applicable provisions of Federal law, the 
regulations in this part, other applicable regulations, any order of 
the Director, the provisions of a lease or grant issued under this 
part, or the requirements of an approved plan or other approval under 
this part.
    (b) BOEM may issue to you a notice of noncompliance if we determine 
that there has been a violation of the regulations in this part, any 
order of the Director, or any provision of your lease, grant or other 
approval issued under this part. When issuing a notice of 
noncompliance, BOEM will serve you at your last known address.
    (c) A notice of noncompliance will tell you how you failed to 
comply with this part, any order of the Director, and/or the provisions 
of your lease, grant or other approval, and will specify what you must 
do to correct the noncompliance and the time limits within which you 
must act.
    (d) Failure of a lessee, operator, or grant holder under this part 
to take the actions specified in a notice of noncompliance within the 
time limit specified provides the basis for BOEM to issue a cessation 
order as provided in Sec.  585.401, and/or a cancellation of the lease 
or grant as provided in Sec.  585.437.
    (e) If BOEM determines that any incident of noncompliance poses an 
imminent threat of serious or irreparable damage to natural resources; 
life (including human and wildlife); property; the marine, coastal, or 
human environment; or sites, structures, or objects of historical or 
archaeological significance, BOEM may include with its notice of 
noncompliance an order directing you to take immediate remedial action 
to alleviate threats and to abate the violation and, when appropriate, 
a cessation order.
    (f) The BOEM may assess civil penalties, as authorized by section 
24 of the OCS Lands Act, if you fail to comply with any provision of 
this part or any term of a lease, grant, or order issued under the 
authority of this part, after notice of such failure and expiration of 
any reasonable period allowed for corrective action. Civil penalties 
will be determined and assessed in accordance with the procedures set 
forth in 30 CFR part 550, subpart N.
    (g) You may be subject to criminal penalties as authorized by 
section 24 of the OCS Lands Act.

Sec.  585.401  When may BOEM issue a cessation order?

    (a) BOEM may issue a cessation order during the term of your lease 
or grant when you fail to comply with an applicable law; regulation; 
order; or provision of a lease, grant, plan, or other BOEM approval 
under this part. Except as provided in Sec.  585.400(e), BOEM will 
allow you a period of time to correct any noncompliance before issuing 
an order to cease activities.
    (b) A cessation order will set forth what measures you are required 
to take, including reports you are required to prepare and submit to 
BOEM, to receive approval to resume activities on your lease or grant.

Sec.  585.402  What is the effect of a cessation order?

    (a) Upon receiving a cessation order, you must cease all activities 
on your lease or grant, as specified in the order. BOEM may authorize 
certain activities during the period of the cessation order.
    (b) A cessation order will last for the period specified in the 
order or as otherwise specified by BOEM. If BOEM determines that the 
circumstances giving rise to the cessation order cannot be resolved 
within a reasonable time period, the Secretary may initiate 
cancellation of your lease or grant, as provided in Sec.  585.437.
    (c) A cessation order does not extend the term of your lease or 
grant for the

[[Page 64745]]

period you are prohibited from conducting activities.
    (d) You must continue to make all required payments on your lease 
or grant during the period a cessation order is in effect.

Sec.  585.403  [Reserved]

Sec.  585.404  [Reserved]

Designation of Operator

Sec.  585.405  How do I designate an operator?

    (a) If you intend to designate an operator who is not the lessee or 
grant holder, you must identify the proposed operator in your SAP 
(under Sec.  585.610(a)(3)), COP (under Sec.  585.626(b)(2)), or GAP 
(under Sec.  585.645(b)(3)), as applicable. If no operator is 
designated in a SAP, COP, or GAP, BOEM will deem the lessee or grant 
holder to be the operator.
    (b) An operator must be designated in any SAP, COP, or GAP if there 
is more than one lessee or grant holder for any individual lease or 
grant.
    (c) Once approved in your plan, the designated operator is 
authorized to act on your behalf and required to perform activities 
necessary to comply with the OCS Lands Act, the lease or grant, and the 
regulations in this part.
    (d) You, or your designated operator, must immediately provide BOEM 
with a written notification of change of address of the lessee or 
operator.
    (e) If there is a change in the designated operator, you must 
provide written notice to BOEM and identify the new designated operator 
within 72 hours on a form approved by BOEM. The lessee(s) or grantee(s) 
is the operator and responsible for compliance until BOEM approves 
designation of the new operator.
    (f) Designation of an operator under any lease or grant issued 
under this part does not relieve the lessee or grant holder of its 
obligations under this part or its lease or grant.
    (g) A designated operator performing activities on the lease must 
comply with all regulations governing those activities and may be held 
liable or penalized for any noncompliance during the time it was 
operator, notwithstanding its subsequent resignation.

Sec.  585.406  Who is responsible for fulfilling lease and grant 
obligations?

    (a) When you are not the sole lessee or grantee, you and your co-
lessee(s) or co-grantee(s) are jointly and severally responsible for 
fulfilling your obligations under the lease or grant and the provisions 
of this part, unless otherwise provided in these regulations.
    (b) If your designated operator fails to fulfill any of your 
obligations under the lease or grant and this part, BOEM may require 
you or any or all of your co-lessees or co-grantees to fulfill those 
obligations or other operational obligations under the OCS Lands Act, 
the lease, grant, or the regulations.
    (c) Whenever the regulations in this part require the lessee or 
grantee to conduct an activity in a prescribed manner, the lessee or 
grantee and operator (if one has been designated) are jointly and 
severally responsible for complying with the regulations.

Sec.  585.407  [Reserved]

Lease or Grant Assignment

Sec.  585.408  May I assign my lease or grant interest?

    (a) You may assign all or part of your lease or grant interest, 
including record title, subject to BOEM approval under this subpart. 
Each instrument that creates or transfers an interest must describe the 
entire tract or describe by officially designated subdivisions the 
interest you propose to create or transfer.
    (b) You may assign a lease or grant interest by submitting one 
paper copy and one electronic copy of an assignment application to 
BOEM. The assignment application must include:
    (1) BOEM-assigned lease or grant number;
    (2) A description of the geographic area or undivided interest you 
are assigning;
    (3) The names of both the assignor and the assignee, if applicable;
    (4) The names and telephone numbers of the contacts for both the 
assignor and the assignee;
    (5) The names, titles, and signatures of the authorizing officials 
for both the assignor and the assignee;
    (6) A statement that the assignee agrees to comply with and to be 
bound by the terms and conditions of the lease or grant;
    (7) The qualifications of the assignee to hold a lease or grant 
under Sec.  585.107; and
    (8) A statement on how the assignee will comply with the financial 
assurance requirements of Sec. Sec.  585.515 through 585.537. No 
assignment will be approved until the assignee provides the required 
financial assurance.
    (c) If you submit an application to assign a lease or grant, you 
will continue to be responsible for payments that are or become due on 
the lease or grant until the date BOEM approves the assignment.
    (d) The assignment takes effect on the date BOEM approves your 
application.
    (e) You do not need to request an assignment for mergers, name 
changes, or changes of business form. You must notify BOEM of these 
events under Sec.  585.109.

Sec.  585.409  How do I request approval of a lease or grant 
assignment?

    (a) You must request approval of each assignment on a form approved 
by BOEM, and submit originals of each instrument that creates or 
transfers ownership of record title or certified copies thereof within 
90 days after the last party executes the transfer agreement.
    (b) Any assignee will be subject to all the terms and conditions of 
your original lease or grant, including the requirement to furnish 
financial assurance in the amount required in Sec. Sec.  585.515 
through 585.537.
    (c) The assignee must submit proof of eligibility and other 
qualifications specified in Sec.  585.107.
    (d) Persons executing on behalf of the assignor and assignee must 
furnish evidence of authority to execute the assignment.

Sec.  585.410  How does an assignment affect the assignor's liability?

    As assignor, you are liable for all obligations, monetary and 
nonmonetary, that accrued under your lease or grant before BOEM 
approves your assignment. Our approval of the assignment does not 
relieve you of these accrued obligations. BOEM may require you to bring 
the lease or grant into compliance to the extent the obligation accrued 
before the effective date of your assignment if your assignee or 
subsequent assignees fail to perform any obligation under the lease or 
grant.

Sec.  585.411  How does an assignment affect the assignee's liability?

    (a) As assignee, you are liable for all lease or grant obligations 
that accrue after BOEM approves the assignment. As assignee, you must 
comply with all the terms and conditions of the lease or grant and all 
applicable regulations, remedy all existing environmental and 
operational problems on the lease or grant, and comply with all 
decommissioning requirements under subpart I of this part.
    (b) Assignees are bound to comply with each term or condition of 
the lease or grant and the regulations in this subchapter. You are 
jointly and severally liable for the performance of all obligations 
under the lease or grant and under the regulations in this part with 
each prior and subsequent lessee who held an interest from the time the 
obligation accrued until it is satisfied, unless this part provides 
otherwise.

[[Page 64746]]

Sec. Sec.  585.412-585.414  [Reserved]

Lease or Grant Suspension

Sec.  585.415  What is a lease or grant suspension?

    (a) A suspension is an interruption of the term of your lease or 
grant that may occur:
    (1) As approved by BOEM at your request, as provided in Sec.  
585.416; or
    (2) As ordered by BOEM, as provided in Sec.  585.417.
    (b) A suspension extends the term of your lease or grant for the 
length of time the suspension is in effect.
    (c) Activities may not be conducted on your lease or grant during 
the period of a suspension except as expressly authorized by BOEM under 
the terms of the suspension.

Sec.  585.416  How do I request a lease or grant suspension?

    You must submit a written request to BOEM that includes the 
following information no later than 90 days prior to the expiration of 
your appropriate lease or grant term:
    (a) The reasons you are requesting suspension of your lease or 
grant term, and the length of additional time requested.
    (b) An explanation of why the suspension is necessary in order to 
ensure full enjoyment of your lease or grant and why it is in the 
lessor's or grantor's interest to approve the suspension.
    (c) If you do not timely submit a SAP, COP, or GAP, as required, 
you may request a suspension to extend the preliminary or site 
assessment term of your lease or grant that includes a revised schedule 
for submission of a SAP, COP, or GAP, as appropriate.
    (d) Any other information BOEM may require.

Sec.  585.417  When may BOEM order a suspension?

    (a) BOEM may order a suspension under the following circumstances:
    (1) When necessary to comply with judicial decrees prohibiting some 
or all activities under your lease;
    (2) When continued activities pose an imminent threat of serious or 
irreparable harm or damage to natural resources; life (including human 
and wildlife); property; the marine, coastal, or human environment; or 
sites, structures, or objects of historical or archaeological 
significance; or
    (3) When the suspension is necessary for reasons of National 
security or defense.
    (b) If BOEM orders a suspension under paragraph (a)(2) of this 
section, and if you wish to resume activities, we may require you to 
conduct a site-specific study that evaluates the cause of the harm, the 
potential damage, and the available mitigation measures. Other 
requirements and actions may occur:
    (1) You may be required to pay for the study;
    (2) You must furnish one paper copy and one electronic copy of the 
study and results to us;
    (3) We will make the results available to other interested parties 
and to the public; and
    (4) We will use the results of the study and any other information 
that become available:
    (i) To decide if the suspension order can be lifted; and
    (ii) To determine any actions that you must take to mitigate or 
avoid any damage to natural resources; life (including human and 
wildlife); property; the marine, coastal, or human environment; or 
sites, structures, or objects of historical or archaeological 
significance.

Sec.  585.418  How will BOEM issue a suspension?

    (a) BOEM will issue a suspension order orally or in writing.
    (b) BOEM will send you a written suspension order as soon as 
practicable after issuing an oral suspension order.
    (c) The written order will explain the reasons for its issuance and 
describe the effect of the suspension order on your lease or grant and 
any associated activities. BOEM may authorize certain activities during 
the period of the suspension, as set forth in the suspension order.

Sec.  585.419  What are my immediate responsibilities if I receive a 
suspension order?

    You must comply with the terms of a suspension order upon receipt 
and take any action prescribed within the time set forth therein.

Sec.  585.420  What effect does a suspension order have on my payments?

    (a) While BOEM evaluates your request for a suspension under Sec.  
585.416, you must continue to fulfill your payment obligation until the 
end of the original term of your lease or grant. If our evaluation goes 
beyond the end of the original term of your lease or grant, the term of 
your lease or grant will be extended for the period of time necessary 
for BOEM to complete its evaluation of your request, but you will not 
be required to make payments during the time of the extension.
    (b) If BOEM approves your request for a suspension, as provided in 
Sec.  585.416, we may suspend your payment obligation, as appropriate 
for the term that is suspended, depending on the reasons for the 
requested suspension.
    (c) If BOEM orders a suspension, as provided in Sec.  585.417, your 
payments, as appropriate for the term that is suspended, will be waived 
during the suspension period.

Sec.  585.421  How long will a suspension be in effect?

    A suspension will be in effect for the period specified by BOEM.
    (a) BOEM will not approve a suspension request pursuant to Sec.  
585.416 for a period longer than 2 years.
    (b) If BOEM determines that the circumstances giving rise to a 
suspension ordered under Sec.  585.417 cannot be resolved within 5 
years, the Secretary may initiate cancellation of the lease or grant, 
as provided in Sec.  585.437.

Sec. Sec.  585.422-585.424  [Reserved]

Lease or Grant Renewal

Sec.  585.425  May I obtain a renewal of my lease or grant before it 
terminates?

    You may request renewal of the operations term of your lease or the 
original authorized term of your grant. BOEM, at its discretion, may 
approve a renewal request to conduct substantially similar activities 
as were originally authorized under the lease or grant. BOEM will not 
approve a renewal request that involves development of a type of 
renewable energy not originally authorized in the lease or grant. BOEM 
may revise or adjust payment terms of the original lease, as a 
condition of lease renewal.

Sec.  585.426  When must I submit my request for renewal?

    (a) You must request a renewal from BOEM:
    (1) No later than 180 days before the termination date of your 
limited lease or grant.
    (2) No later than 2 years before the termination date of the 
operations term of your commercial lease.
    (b) You must submit to BOEM all information we request pertaining 
to your lease or grant and your renewal request.

Sec.  585.427  How long is a renewal?

    BOEM will set the term of a renewal at the time of renewal on a 
case-by-case basis.
    (a) For commercial leases, a renewal term will not exceed the 
original operations term unless a longer term is negotiated by the 
applicable parties.
    (b) For limited leases, a renewal term will not exceed the original 
operations term.

[[Page 64747]]

    (c) For RUE and ROW grants, a renewal will continue for as long as 
the associated activities are conducted and facilities properly 
maintained and used for the purpose for which the grant was made, 
unless otherwise expressly stated.

Sec.  585.428  What effect does applying for a renewal have on my 
activities and payments?

    If you timely request a renewal:
    (a) You may continue to conduct activities approved under your 
lease or grant under the original terms and conditions for as long as 
your request is pending decision by BOEM.
    (b) You may request a suspension of your lease or grant, as 
provided in Sec.  585.416, while we consider your request.
    (c) For the period BOEM considers your request for renewal, you 
must continue to make all payments in accordance with the original 
terms and conditions of your lease or grant.

Sec.  585.429  What criteria will BOEM consider in deciding whether to 
renew a lease or grant?

    BOEM will consider the following criteria in deciding whether to 
renew a lease or grant:
    (a) Design life of existing technology.
    (b) Availability and feasibility of new technology.
    (c) Environmental and safety record of the lessee or grantee.
    (d) Operational and financial compliance record of the lessee or 
grantee.
    (e) Competitive interest and fair return considerations.
    (f) Effects of the lease or grant on generation capacity and 
reliability within the regional electrical distribution and 
transmission system.

Sec.  585.430  [Reserved]

Sec.  585.431  [Reserved]

Lease or Grant Termination

Sec.  585.432  When does my lease or grant terminate?

    Your lease or grant terminates on whichever of the following dates 
occurs first:
    (a) The expiration of the applicable term of your lease or grant, 
unless your term is automatically extended under Sec. Sec.  585.235 or 
585.236, a request for renewal of your lease or grant is pending a 
decision by BOEM, or your lease or grant is suspended or renewed as 
provided in this subpart;
    (b) A cancellation, as set forth in Sec.  585.437; or
    (c) Relinquishment, as set forth in Sec.  585.435.

Sec.  585.433  What must I do after my lease or grant terminates?

    (a) After your lease or grant terminates, you must:
    (1) Make all payments due, including any accrued rentals and 
deferred bonuses; and
    (2) Perform any other outstanding obligations under the lease or 
grant within 6 months.
    (b) Within 2 years following termination of a lease or grant, you 
must remove or dispose of all facilities, installations, and other 
devices permanently or temporarily attached to the seabed on the OCS in 
accordance with a plan or application approved by BOEM under subpart I 
of this part.
    (c) If you fail to comply with your approved decommissioning plan 
or application:
    (1) BOEM may call for the forfeiture of your financial assurance; 
and
    (2) You remain liable for removal or disposal costs and responsible 
for accidents or damages that might result from such failure.

Sec.  585.434  [Reserved]

Lease or Grant Relinquishment

Sec.  585.435  How can I relinquish a lease or a grant or parts of a 
lease or grant?

    (a) You may surrender the lease or grant, or an officially 
designated subdivision thereof, by filing one paper copy and one 
electronic copy of a relinquishment application with BOEM. A 
relinquishment takes effect on the date we approve your application, 
subject to the continued obligation of the lessee and the surety to:
    (1) Make all payments due on the lease or grant, including any 
accrued rent and deferred bonuses;
    (2) Decommission all facilities on the lease or grant to be 
relinquished to the satisfaction of BOEM; and
    (3) Perform any other outstanding obligations under the lease or 
grant.
    (b) Your relinquishment application must include:
    (1) Name;
    (2) Contact name;
    (3) Telephone number;
    (4) Fax number;
    (5) E-mail address;
    (6) BOEM-assigned lease or grant number, and, if applicable, the 
name of any facility;
    (7) A description of the geographic area you are relinquishing;
    (8) The name, title, and signature of your authorizing official 
(the name, title, and signature must match exactly the name, title, and 
signature in BOEM qualification records); and
    (9) A statement that you will adhere to the requirements of subpart 
I of this part.
    (c) If you have submitted an application to relinquish a lease or 
grant, you will be billed for any outstanding payments that are due 
before the relinquishment takes effect, as provided in paragraph (a) of 
this section.

Lease or Grant Contraction

Sec.  585.436  Can BOEM require lease or grant contraction?

    At an interval no more frequent than every 5 years, the BOEM may 
review your lease or grant area to determine whether the lease or grant 
area is larger than needed to develop the project and manage activities 
in a manner that is consistent with the provisions of this part. BOEM 
will notify you of our proposal to contract the lease or grant area.
    (a) BOEM will give you the opportunity to present orally or in 
writing information demonstrating that you need the area in question to 
manage lease or grant activities consistent with these regulations.
    (b) Prior to taking action to contract the lease or grant area, 
BOEM will issue a decision addressing your contentions that the area is 
needed.
    (c) You may appeal this decision under Sec.  585.118 of this part.

Lease or Grant Cancellation

Sec.  585.437  When can my lease or grant be canceled?

    (a) The Secretary will cancel any lease or grant issued under this 
part upon proof that it was obtained by fraud or misrepresentation, and 
after notice and opportunity to be heard has been afforded to the 
lessee or grant holder.
    (b) The Secretary may cancel any lease or grant issued under this 
part when:
    (1) The Secretary determines after notice and opportunity for a 
hearing that, with respect to the lease or grant that would be 
canceled, the lessee or grantee has failed to comply with any 
applicable provision of the OCS Lands Act or these regulations; any 
order of the Director; or any term, condition or stipulation contained 
in the lease or grant, and that the failure to comply continued 30 days 
(or other period BOEM specifies) after you receive notice from BOEM. 
The Secretary will mail a notice by registered or certified letter to 
the lessee or grantee at its record post office address;
    (2) The Secretary determines after notice and opportunity for a 
hearing that you have terminated commercial operations under your COP, 
as provided in Sec.  585.635, or other approved activities under your 
GAP, as provided in Sec.  585.656;

[[Page 64748]]

    (3) Required by National security or defense; or
    (4) The Secretary determines after notice and opportunity for a 
hearing that continued activity under the lease or grant:
    (i) Would cause serious harm or damage to natural resources; life 
(including human and wildlife); property; the marine, coastal, or human 
environment; or sites, structures, or objects of historical or 
archaeological significance; and
    (ii) That the threat of harm or damage would not disappear or 
decrease to an acceptable extent within a reasonable period of time; 
and
    (iii) The advantages of cancellation outweigh the advantages of 
continuing the lease or grant in force.

Subpart E--Payments and Financial Assurance Requirements

Payments

Sec.  585.500  How do I make payments under this part?

    (a) For acquisition fees or the initial 6-months rent paid for the 
preliminary term of your lease, you must make credit card or automated 
clearing house payments through the Pay.gov Web site, and you must 
include one copy of the Pay.gov confirmation receipt page with your 
unsolicited request or signed lease instrument. You may access the 
Pay.gov Web site through links on the BOEM Offshore Web site at: http://www.boem.gov/offshore or directly through Pay.gov at: https://www.pay.gov/paygov/.
    (b) For rent during the preliminary term, subsequent to the first 
6-months rent, or the site assessment term; or operating fees during 
the operations term, you must make your payments as required in 30 CFR 
1218.51 of this chapter.
    (c) This table summarizes payments you must make for leases and 
grants, unless otherwise specified in the Final Sale Notice:

--------------------------------------------------------------------------------------------------------------------------------------------------------
                                             Payment                 Amount                 Due date          Payment mechanism      Section reference
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                               Initial payments for leases
--------------------------------------------------------------------------------------------------------------------------------------------------------
(1) If your lease is issued          Bid Deposit...........  As set in Final Sale    With bid.............  Pay.Gov..............  Sec.   585.501.
 competitively,                                               Notice/depends on bid.
                                     Bonus Balance.........  ......................  Lease issuance.......  30 CFR 1218.51.......
(2) If your lease is issued non-     Acquisition Fee.......  $0.25 per acre, unless  With application.....  Pay.gov..............  Sec.   585.502.
 competitively.                                               otherwise set by the
                                                              Director.
(3) All leases.....................  Initial Rent..........  $3 per acre per year..  45 days after lease    Pay.gov..............  Sec.   585.503.
                                                                                      issuance.
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                  Subsequent payments for leases and project easements
--------------------------------------------------------------------------------------------------------------------------------------------------------
(4) All leases.....................  Subsequent Rent.......  $3 per acre per year..  Annually.............  30 CFR 1218.51.......  Sec.  Sec.   585.503
                                                                                                                                    and 585.504.
(5) If you have a project easement.  Rent..................  Greater of $5 per acre  When operations term   30 CFR 1218.51.......  Sec.   585.507.
                                                              per year or $450 per    for associated lease
                                                              year.                   starts, then
                                                                                      annually.
(7) If your commercial lease is      Operating Fee.........  Determined by the       Annually.............  30 CFR 1218.51.......  Sec.   585.506.
 producing,                                                   formula in Sec.
                                                              585.506.
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                         Payments for ROW grants and RUE grants*
--------------------------------------------------------------------------------------------------------------------------------------------------------
(8) All ROW grants and RUE grants..  Initial Rent..........  $70 per statute mile,   Grant Issuance.......  Pay.gov..............  Sec.   585.508.
                                                              and the greater of $5
                                                              per acre per year or
                                                              $450 per year.
                                     Subsequent Rent.......  ......................  Annually or in 5-year  30 CFR 1218.51.......
                                                                                      batches.
--------------------------------------------------------------------------------------------------------------------------------------------------------
* There is no acquisition fee for ROW grants or RUE grants.

Sec.  585.501  What deposits must I submit for a competitively issued 
lease, ROW grant, or RUE grant?

    (a) For a competitive lease or grant that we offer through sealed 
bidding, you must submit a deposit of 20 percent of the total bid 
amount, unless some other amount is specified in the Final Sale Notice.
    (b) For a competitive lease that we offer through ascending 
bidding, you must submit a deposit as established in the Final Sale 
Notice.
    (c) You must pay any balances on accepted high bids in accordance 
with the Final Sale Notice, this part, and your lease or grant 
instrument.
    (d) The deposit will be forfeited for any successful bidder who 
fails to execute the lease within the prescribed time, or otherwise 
does not comply with the regulations concerning acquisition of a lease 
or grant or stipulations in the Final Sale Notice.

Sec.  585.502  What initial payment requirements must I meet to obtain 
a noncompetitive lease, ROW grant, or RUE grant?

    When requesting a noncompetitive lease, you must meet the initial 
payment (acquisition fee) requirements of this section, unless 
specified otherwise in your lease instrument. No initial payment is 
required when requesting noncompetitive ROW grants and RUE grants.
    (a) If you request a noncompetitive lease, you must submit an 
acquisition fee of $0.25 per acre, unless otherwise

[[Page 64749]]

set by the Director, as provided in Sec.  585.500.
    (b) If BOEM determines there is no competitive interest, we will 
then:
    (1) Retain your acquisition fee if we issue you a lease; or
    (2) Refund your acquisition fee, without interest, if we do not 
issue your requested lease.
    (c) If we determine that there is a competitive interest in an area 
you requested, then we will proceed with a competitive lease sale 
process provided for in subpart B of this part, and we will:
    (1) Apply your acquisition fee to the required deposit for your bid 
amount if you submit a bid;
    (2) Apply your acquisition fee to your bonus bid if you acquire the 
lease; or
    (3) Retain your acquisition fee if you do not bid for or acquire 
the lease.

Sec.  585.503  What are the rent and operating fee requirements for a 
commercial lease?

    (a) The rent for a commercial lease is $3 per acre per year, unless 
otherwise established in the Final Sale Notice or lease.
    (1) You must pay ONRR, under the regulations at 30 CFR part 1218, 
the first 6-months rent, as provided in Sec.  585.500, 45 days after we 
issue your lease.
    (2) You must pay ONRR, under the regulations at 30 CFR part 1218, 
rent at the beginning of each subsequent 1-year period in accordance 
with the regulations at 30 CFR 1218.51 for the entire lease area until 
the facility begins to generate commercially, as specified in Sec.  
585.506 or as otherwise specified in the Final Sale Notice or lease 
instrument:
    (i) For leases issued competitively, the BOEM will specify in the 
Final Sale Notice and lease any adjustment to the rent fee to take 
effect during the operations term and prior to the commercial 
generation.
    (ii) For leases issued noncompetitively, the BOEM will specify in 
the lease any adjustment to the rent fee to take effect during the 
operations term and prior to the commercial generation.
    (3) You must pay ONRR, under the regulations at 30 CFR part 1218, 
the rent for a project easement in addition to the lease rent, as 
provided in Sec.  585.507. You must commence rent payments for your 
project easement upon our approval of your COP or GAP.
    (b) After your lease begins commercial generation of electricity or 
on the date specified by BOEM, you must pay operating fees in the 
amount specified in Sec.  585.506:
    (1) For leases issued competitively, BOEM will specify in the Final 
Sale Notice and lease the date when operating fees commence; and
    (2) For leases issued noncompetitively, BOEM will specify in the 
lease the date when operating fee commences.

Sec.  585.504  How are my payments affected if I develop my lease in 
phases?

    If you develop your commercial lease in phases, as approved by us 
in your COP under Sec.  585.629, you must pay ONRR, under the 
regulations at 30 CFR part 1218:
    (a) Rent on the portion of the lease that is not authorized for 
commercial operations.
    (b) Operating fees on the portion of the lease that is authorized 
for commercial operations, in the amount specified in Sec.  585.506 and 
as described in Sec.  585.503(b).
    (c) Rent for a project easement in addition to lease rent, as 
provided in Sec.  585.507. You must commence rent payments for your 
project easement upon our approval of your COP.

Sec.  585.505  What are the rent and operating fee requirements for a 
limited lease?

    (a) The rent for a limited lease is $3 per acre per year, unless 
otherwise established in the Final Sale Notice and your lease 
instrument.
    (b) You must pay ONRR, under the regulations at 30 CFR part 1218, 
the first 6-months rent when BOEM issues your limited lease, as 
provided in Sec.  585.500.
    (c) You must pay ONRR, under the regulations at 30 CFR part 1218, 
rent at the beginning of each subsequent 1-year period on the entire 
lease area for the duration of your operations term in accordance with 
the regulations at 30 CFR 1218.51.
    (d) BOEM will not charge an operating fee for the authorized sale 
of power from a limited lease.

Sec.  585.506  What operating fees must I pay on a commercial lease?

    If you are generating electricity, you must pay ONRR, under the 
regulations at 30 CFR part 1218, operating fees on your commercial 
lease when you begin commercial generation, as described in Sec.  
585.503.
    (a) BOEM will determine the annual operating fee for activities 
relating to the generation of electricity on your lease based on the 
following formula,

F = M * H * c * P * r,

Where:

(1) F is the dollar amount of the annual operating fee;
(2) M is the nameplate capacity expressed in megawatts;
(3) H is the number of hours in a year, equal to 8,760, used to 
calculate an annual payment;
(4) c is the ``capacity factor'' representing the anticipated 
efficiency of the facility's operation expressed as a decimal 
between zero and one;
(5) P is a measure of the annual average wholesale electric power 
price expressed in dollars per megawatt hour, as provided in 
paragraph (c)(2) of this section; and
(6) r is the operating fee rate expressed as a decimal between zero 
and one.

    (b) The annual operating fee formula relating to the value of 
annual electricity generation is restated as:

--------------------------------------------------------------------------------------------------------------------------------------------------------
                                         M (nameplate             H (hours per            c (capacity                                   r (operating fee
    F (annual operating fee)      =        capacity)       *         year)         *        factor)        *    P (power price)    *         rate)
--------------------------------------------------------------------------------------------------------------------------------------------------------
 
--------------------------------------------------------------------------------------------------------------------------------------------------------

     (c) BOEM will specify operating fee parameters in the Final Sale 
Notice for commercial leases issued competitively and in the lease for 
those issued noncompetitively.
    (1) Unless BOEM specifies otherwise, in the operating fee rate, 
``r'' is 0.02 for each year the operating fee applies when you begin 
commercial generation of electricity. We may apply a different fee rate 
for new projects (i.e., a new generation based on new technology) after 
considering factors such as program objectives, state of the industry, 
project type, and project potential. Also, we may agree to reduce or 
waive the fee rate under Sec.  585.510.
    (2) The power price ``P,'' for each year when the operating fee 
applies, will be determined annually. The process by which the power 
price will be determined will be specified in the Final Sale Notice 
and/or in the lease. BOEM:
    (i) Will use the most recent annual average wholesale power price 
in the State in which a project's transmission cables make landfall, as 
published by the DOE, Energy Information Administration (EIA), or other 
publicly

[[Page 64750]]

available wholesale power price indices; and
    (ii) May adjust the published average wholesale power price to 
reflect documented variations by State or within a region and recent 
market conditions.
    (3) BOEM will select the capacity factor ``c'' based upon 
applicable analogs drawn from present and future domestic and foreign 
projects that operate in comparable conditions and on comparable 
scales.
    (i) Upon the completion of the first year of commercial operations 
on the lease, BOEM may adjust the capacity factor as necessary (to 
accurately represent a comparison of actual production over a given 
period of time with the amount of power a facility would have produced 
if it had run at full capacity) in a subsequent year.
    (ii) After the first adjustment, BOEM may adjust the capacity 
factor (to accurately represent a comparison of actual generation over 
a given period of time with the amount of power a facility would have 
generated if it had run at full capacity) no earlier than in 5-year 
intervals from the most recent year that BOEM adjusts the capacity 
factor.
    (iii) The process by which BOEM will adjust the capacity factor, 
including any calculations (incorporating an average capacity factor 
reflecting actual operating experience), will be specified in the 
lease. The operator or lessee may request review and adjustment of the 
capacity factor under Sec.  585.510.
    (4) Ten days after the anniversary date of when you began to 
commercially generate electricity, you must submit to BOEM 
documentation of the gross annual generation of electricity produced by 
the generating facility on the lease. You must use the same information 
collection form as authorized by the EIA for this information.
    (5) For the nameplate capacity ``M,'' BOEM will use the total 
installed capacity of the equipment you install, as specified in your 
approved COP.
    (d) You must submit all operating fee payments to BOEM in 
accordance with the provisions under 30 CFR 1218.51.
    (e) BOEM will establish the operating fee in the Final Sale Notice 
or in the lease on a case-by-case basis for:
    (1) Activities that do not relate to the generation of electricity 
(e.g., hydrogen production), and
    (2) Leases issued for hydrokinetic activities requiring a FERC 
license.

Sec.  585.507  What rent payments must I pay on a project easement?

    (a) You must pay ONRR, under the regulations at 30 CFR part 1218, a 
rent fee for your project easement of $5 per acre, subject to a minimum 
of $450 per year, unless specified otherwise in the Final Sale Notice 
or lease:
    (1) The size of the project easement area for a cable or a pipeline 
is the full length of the corridor and a width of 200 feet (61 meters), 
centered on the cable or pipeline; and
    (2) The size of a project easement area for an accessory platform 
is limited to the aerial extent of anchor chains and other facilities 
and devices associated with the accessory.
    (b) You must commence rent payments for your project easement upon 
our approval of your COP or GAP:
    (1) You must make the first rent payment when the operations term 
begins, as provided in Sec.  585.500;
    (2) You must submit all subsequent rent payments in accordance with 
the regulations at 30 CFR 1218.51; and
    (3) You must continue to pay annual rent for your project easement 
until your lease is terminated.

Sec.  585.508  What rent payments must I pay on ROW grants or RUE 
grants associated with renewable energy projects?

    (a) For each ROW grant BOEM approves under subpart C of this part, 
you must pay ONRR, under the regulations at 30 CFR part 1218, an annual 
rent as follows, unless specified otherwise in the Final Sale Notice:
    (1) A fee of $70 for each nautical mile or part of a nautical mile 
of the OCS that your ROW crosses; and
    (2) An additional $5 per acre, subject to a minimum of $450 for use 
of the entire affected area, if you hold a ROW grant that includes a 
site outside the corridor of a 200-foot width (61 meters), centered on 
the cable or pipeline. The affected area includes the areal extent of 
anchor chains, risers, and other devices associated with a site outside 
the corridor.
    (b) For each RUE grant BOEM approves under subpart C of this part, 
you must pay ONRR, under the regulations at 30 CFR part 1218, a rent 
of:
    (1) $5 per acre per year; or
    (2) A minimum of $450 per year.
    (c) You must make the rent payments required by paragraphs (a) and 
(b) of this section on:
    (1) An annual basis;
    (2) For a 5-year period; or
    (3) For multiples of 5 years.
    (d) You must make the first annual rent payment upon approval of 
your ROW grant or RUE grant request, as provided in Sec.  585.500, and 
all subsequent rent payments to ONRR in accordance with the regulations 
at 30 CFR 1218.51.

Sec.  585.509  Who is responsible for submitting lease or grant 
payments to BOEM?

    (a) For each lease, ROW grant, or RUE grant issued under this part, 
you must identify one person who is responsible for all payments due 
and payable under the provisions of the lease or grant. The responsible 
person identified is designated as the payor, and you must document 
acceptance of such responsibilities, as provided in 30 CFR 1218.52.
    (b) All payors must submit payments and maintain auditable records 
in accordance with guidance we issue or any applicable regulations in 
subchapter A of this chapter. In addition, the lessee or grant holder 
must also maintain such auditable records.

Sec.  585.510  May BOEM reduce or waive my lease or grant payments?

    (a) BOEM Director may reduce or waive the rent or operating fee or 
components of the operating fee, such as the fee rate or capacity 
factor, when the Director determines that it is necessary to encourage 
continued or additional activities.
    (b) When requesting a reduction or waiver, you must submit an 
application to us that includes all of the following:
    (1) The number of the lease, ROW grant, or RUE grant involved;
    (2) Name of each lessee or grant holder of record;
    (3) Name of each operator;
    (4) A demonstration that:
    (i) Continued activities would be uneconomic without the requested 
reduction or waiver, or
    (ii) A reduction or waiver is necessary to encourage additional 
activities; and
    (5) Any other information required by the Director.
    (c) No more than 6 years of your operations term will be subject to 
a full waiver of the operating fee.

Sec.  585.511-585.514  [Reserved]

Financial Assurance Requirements for Commercial Leases

Sec.  585.515  What financial assurance must I provide when I obtain my 
commercial lease?

    (a) Before BOEM will issue your commercial lease or approve an 
assignment of an existing commercial lease, you (or, for an assignment, 
the proposed assignee) must guarantee compliance with all terms and 
conditions of the lease by providing either:
    (1) A $100,000 minimum, lease-specific bond; or
    (2) Another approved financial assurance instrument guaranteeing

[[Page 64751]]

performance up to $100,000, as specified in Sec. Sec.  585.526 through 
585.529.
    (b) You meet the financial assurance requirements under this 
subpart if your designated lease operator provides a $100,000 minimum, 
lease-specific bond or other approved financial assurance that 
guarantees compliance with all terms and conditions of the lease.
    (1) The dollar amount of the minimum, lease-specific financial 
assurance in paragraphs (a)(1) and (b) of this section will be adjusted 
to reflect changes in the Consumer Price Index-All Urban Consumers 
(CPI-U) or a substantially equivalent index if the CPI-U is 
discontinued; and
    (2) The first CPI-U-based adjustment can be made no earlier than 
the 5-year anniversary of the adoption of this rule. Subsequent CPI-U-
based adjustments may be made every 5 years thereafter.

Sec.  585.516  What are the financial assurance requirements for each 
stage of my commercial lease?

    (a) The basic financial assurance requirements for each stage of 
your commercial lease are as follows:

------------------------------------------------------------------------
         Before BOEM will . . .               You must provide . . .
------------------------------------------------------------------------
(1) Issue a commercial lease or approve  A $100,000 minimum, lease-
 an assignment of an existing             specific financial assurance.
 commercial lease.
(2) Approve your SAP...................  A supplemental bond or other
                                          financial assurance, in an
                                          amount determined by BOEM, if
                                          upon reviewing your SAP, BOEM
                                          determines that a supplemental
                                          bond is required in addition
                                          to your minimum lease-specific
                                          bond, due to the complexity,
                                          number, and location of any
                                          facilities involved in your
                                          site assessment activities.
(3) Approve your COP...................  A supplemental bond or other
                                          financial assurance, in an
                                          amount determined by BOEM
                                          based on the complexity,
                                          number, and location of all
                                          facilities involved in your
                                          planned activities and
                                          commercial operation. The
                                          supplemental financial
                                          assurance requirement is in
                                          addition to your lease-
                                          specific bond and, if
                                          applicable, the previous
                                          supplement associated with SAP
                                          approval.
(4) Allow you to install facilities      A decommissioning bond or other
 approved in your COP.                    financial assurance, in an
                                          amount determined by BOEM
                                          based on anticipated
                                          decommissioning costs. BOEM
                                          will allow you to provide your
                                          financial assurance for
                                          decommissioning in accordance
                                          with the number of facilities
                                          installed or being installed.
                                          BOEM must approve the schedule
                                          for providing the appropriate
                                          financial assurance coverage.
------------------------------------------------------------------------

    (b) Each bond or other financial assurance must guarantee 
compliance with all terms and conditions of the lease. You may provide 
a new bond or increase the amount of your existing bond, to satisfy any 
additional financial assurance requirements.
    (c) For hydrokinetic commercial leases, supplemental financial 
assurance may be required in an amount determined by BOEM before FERC 
issues a license.

Sec.  585.517  How will BOEM determine the amounts of the supplemental 
and decommissioning financial assurance requirements associated with 
commercial leases?

    (a) BOEM will base the determination for the amounts of the SAP, 
COP, and decommissioning financial assurance requirements on estimates 
of the cost to meet all accrued lease obligations.
    (b) We determine the amount of the supplemental and decommissioning 
financial assurance requirements on a case-by-case basis. The amount of 
the financial assurance must be no less than the amount required to 
meet all lease obligations, including:
    (1) The projected amount of rent and other payments due the 
Government over the next 12 months;
    (2) Any past due rent and other payments;
    (3) Other monetary obligations; and
    (4) The estimated cost of facility decommissioning, as required by 
subpart I of this part.
    (c) If your cumulative potential obligations and liabilities 
increase or decrease, we may adjust the amount of supplemental or the 
decommissioning financial assurance.
    (1) If we propose adjusting your financial assurance amount, we 
will notify you of the proposed adjustment and give you an opportunity 
to comment; and
    (2) We may approve a reduced financial assurance amount if you 
request it and if the reduced amount that you request continues to be 
greater than the sum of:
    (i) The projected amount of rent and other payments due the 
Government over the next 12 months;
    (ii) Any past due rent and other payments;
    (iii) Other monetary obligations; and
    (iv) The estimated cost of facility decommissioning.

Sec. Sec.  585.518-585.519  [Reserved]

Financial Assurance for Limited Leases, ROW Grants, and RUE Grants

Sec.  585.520  What financial assurance must I provide when I obtain my 
limited lease, ROW grant, or RUE grant?

    (a) Before BOEM will issue your limited lease, ROW grant, or RUE 
grant, you or a proposed assignee must guarantee compliance with all 
terms and conditions of the lease or grant by providing either:
    (1) A $300,000 minimum, lease- or grant-specific bond; or
    (2) Another approved financial assurance instrument of such minimum 
level as specified in Sec. Sec.  585.526 through 585.529.
    (b) You meet the financial assurance requirements under this 
subpart if your designated lease or grant operator provides a minimum 
limited lease-specific or grant-specific bond in an amount sufficient 
to guarantee compliance with all terms and conditions of the limited 
lease or grant.
    (1) The dollar amount of the minimum, lease- or grant-specific 
financial assurance in paragraph (a)(1) of this section will be 
adjusted to reflect changes in the CPI-U or a substantially equivalent 
index if the CPI-U is discontinued; and
    (2) The first CPI-U-based adjustment can be made no earlier than 
the 5-year anniversary of the adoption of this rule. Subsequent CPI-U-
based adjustments may be made every 5 years thereafter.

Sec.  585.521  Do my financial assurance requirements change as 
activities progress on my limited lease or grant?

    (a) BOEM may require you to increase the level of your financial 
assurance as activities progress on your limited lease or grant. We 
will base the determination

[[Page 64752]]

for the amount of financial assurance requirements on our estimate of 
the cost to meet all accrued lease or grant obligations, including:
    (1) The projected amount of rent and other payments due the 
Government over the next 12 months;
    (2) Any past due rent and other payments;
    (3) Other monetary obligations; and
    (4) The estimated cost of facility decommissioning.
    (b) You may satisfy the requirement for increased financial 
assurance levels for the limited lease or grant by increasing the 
amount of your existing bond or replacing your existing bond.
    (c) BOEM will authorize you to establish a separate decommissioning 
bond or other financial assurance for your limited lease or grant.
    (1) The separate decommissioning bond or other financial assurance 
instrument must meet the requirements specified in Sec. Sec.  585.525 
through 585.529.
    (2) BOEM will allow you to provide your financial assurance for 
decommissioning in accordance with the number of facilities installed 
or being installed. BOEM must approve the schedule for providing the 
appropriate financial assurance coverage.

Sec. Sec.  585.522-585.524  [Reserved]

Requirements for Financial Assurance Instruments

Sec.  585.525  What general requirements must a financial assurance 
instrument meet?

    (a) Any bond or other acceptable financial assurance instrument 
that you provide must:
    (1) Be payable to BOEM upon demand; and
    (2) Guarantee compliance of all lessees, grant holders, operators, 
and payors with all terms and conditions of the lease or grant, any 
subsequent approvals and authorizations, and all applicable 
regulations.
    (b) All bonds and other forms of financial assurance must be on or 
in a form approved by BOEM. You may submit this on an approved form 
that you have reproduced or generated by use of a computer. If the 
document you submit omits any terms and conditions that are included on 
the BOEM-approved form, your bond is deemed to contain the omitted 
terms and conditions.
    (c) Surety bonds must be issued by an approved surety listed in the 
current Treasury Circular 570, as required by 31 CFR 223.16. You may 
obtain a copy of Circular 570 from the Treasury Web site at http://www.fms.treas.gov/c570/.
    (d) Your surety bond cannot exceed the underwriting limit listed in 
the current Treasury Circular 570, except as permitted therein.
    (e) You and a qualified surety must execute your bond. When the 
surety is a corporation, an authorized corporate officer must sign the 
bond and attest to it over the corporate seal.
    (f) You may not terminate the period of liability of your bond or 
cancel your bond, except as provided in this subpart. Bonds must 
continue in full force and effect even though an event has occurred 
that could diminish or terminate a surety's obligation under State law.
    (g) Your surety must notify you and BOEM within 5 business days 
after:
    (1) It initiates any judicial or administrative proceeding alleging 
its insolvency or bankruptcy; or
    (2) The Treasury decertifies the surety.

Sec.  585.526  What instruments other than a surety bond may I use to 
meet the financial assurance requirement?

    (a) You may use other types of security instruments, if BOEM 
determines that such security protects BOEM to the same extent as the 
surety bond. BOEM will consider pledges of the following:
    (1) U.S. Department of Treasury securities identified in 31 CFR 
part 225;
    (2) Cash in an amount equal to the required dollar amount of the 
financial assurance, to be deposited and maintained in a Federal 
depository account of the U.S. Treasury by BOEM;
    (3) Certificates of deposit or savings accounts in a bank or 
financial institution organized or authorized to transact business in 
the United States with:
    (i) Minimum net assets of $500,000,000; and
    (ii) Minimum Bankrate.com Safe & Sound rating of 3 Stars, and 
Capitalization, Assets, Equity and Liquidity (CAEL) rating of 3 or 
less;
    (4) Negotiable U.S. Government, State, and municipal securities or 
bonds having a market value of not less than the required dollar amount 
of the financial assurance and maintained in a Securities Investors 
Protection Corporation insured trust account by a licensed securities 
brokerage firm for the benefit of the BOEM;
    (5) Investment-grade rated securities having a Standard and Poor's 
rating of AAA or an equivalent rating from a nationally recognized 
securities rating service having a market value of not less than the 
required dollar amount of the financial assurance and maintained in a 
Securities Investors Protection Corporation insured trust account by a 
licensed securities brokerage firm for the benefit of BOEM; and
    (6) Insurance, if its form and function is such that the funding or 
enforceable pledges of funding are used to guarantee performance of 
regulatory obligations in the event of default on such obligations by 
the lessee. Insurance must have an A.M. Best rating of ``superior'' or 
an equivalent rating from a nationally recognized insurance rating 
service.
    (b) If you use a Treasury security:
    (1) You must post 115 percent of your financial assurance amount;
    (2) You must monitor the collateral value of your security. If the 
collateral value of your security as determined in accordance with the 
31 CFR part 203 Collateral Margins Table (which can be found at http://www.treasurydirect.gov) falls below the required level of coverage, you 
must pledge additional security to provide 115 percent of the required 
amount; and
    (3) You must include with your pledge authority for us to sell the 
security and use the proceeds if we determine that you have failed to 
comply with any of the terms and conditions of your lease or grant, any 
subsequent approval or authorization, or applicable regulations.
    (c) If you use the instruments described in paragraphs (a)(4) or 
(a)(5) of this section, you must provide BOEM by the end of each 
calendar year a certified statement describing the nature and market 
value of the instruments maintained in that account, and including any 
current statements or reports furnished by the brokerage firm to the 
lessee concerning the asset value of the account.

Sec.  585.527  May I demonstrate financial strength and reliability to 
meet the financial assurance requirement for lease or grant activities?

    BOEM may allow you to use your financial strength and reliability 
to meet financial assurance requirements. We will make this 
determination based on audited financial statements, business 
stability, reliability, and compliance with regulations.
    (a) You must provide the following information if you want to 
demonstrate financial strength and reliability to meet your financial 
assurance requirements:
    (1) Audited financial statements (including auditor's certificate, 
balance sheet, and profit and loss sheet) that show you have financial 
capacity substantially in excess of existing and anticipated lease and 
other obligations;
    (2) Evidence that shows business stability based on 5 years of 
continuous operation and generation of renewable energy on the OCS or 
onshore;
    (3) Evidence that shows reliability in meeting obligations based on 
credit

[[Page 64753]]

ratings or trade references, including names and addresses of other 
lessees, contractors, and suppliers with whom you have dealt; and
    (4) Evidence that shows a record of compliance with laws, 
regulations, and lease, ROW, or RUE terms.
    (b) If we approve your request to use your financial strength and 
reliability to meet your financial assurance requirements, you must 
submit annual updates to the information required by paragraph (a) of 
this section. You must submit this information no later than March 31 
of each year.
    (c) If the annual updates to the information required by paragraph 
(a) of this section do not continue to demonstrate financial strength 
and reliability or BOEM has reason to believe that you are unable to 
meet the financial assurance requirements of this section, after notice 
and opportunity for a hearing, BOEM will terminate your ability to use 
financial strength and reliability for financial assurance and require 
you to provide another type of financial assurance. You must provide 
this new financial assurance instrument within 90 days after we 
terminate your use of financial strength and reliability.

Sec.  585.528  May I use a third-party guaranty to meet the financial 
assurance requirement for lease or grant activities?

    (a) You may use a third-party guaranty if the guarantor meets the 
criteria prescribed in paragraph (b) of this section and submits an 
agreement meeting the criteria prescribed in paragraph (c) of this 
section. The agreement must guarantee compliance with the obligations 
of all lessees and operators and grant holders.
    (b) BOEM will consider the following factors in deciding whether to 
accept an agreement:
    (1) The length of time that your guarantor has been in continuous 
operation as a business entity. You may exclude periods of interruption 
that are beyond the guarantor's control by demonstrating, to the 
satisfaction of the Director, that the interruptions do not affect the 
likelihood of your guarantor remaining in business during the SAP, COP, 
and decommissioning stages of activities covered by the indemnity 
agreement.
    (2) Financial information available in the public record or 
submitted by your guarantor in sufficient detail to show us that your 
guarantor meets the criterion stated in paragraph (b)(4) of this 
section. Such detail includes:
    (i) The current rating for your guarantor's most recent bond 
issuance by a generally recognized bond rating service such as Moody's 
Investor Service or Standard and Poor's Corporation;
    (ii) Your guarantor's net worth, taking into account liabilities 
for compliance with all terms and conditions of your lease, 
regulations, and other guarantees;
    (iii) Your guarantor's ratio of current assets to current 
liabilities, taking into account liabilities for compliance with all 
terms and conditions of your lease, regulations, and other guarantees; 
and
    (iv) Your guarantor's unencumbered domestic fixed assets.
    (3) If the information in paragraph (b)(2) of this section is not 
publicly available, your guarantor must submit the information in the 
following table, to be updated annually within 90 days of the end of 
the fiscal year (FY) or as otherwise prescribed.

------------------------------------------------------------------------
    Your guarantor must submit . . .                That . . .
------------------------------------------------------------------------
(i) Financial statements for the most    Include a report by an
 recently completed FY.                   independent certified public
                                          accountant containing the
                                          accountant's audit or review
                                          opinion of the statements. The
                                          report must be prepared in
                                          conformance with generally
                                          accepted accounting principles
                                          and contain no adverse
                                          opinion.
(ii) Financial statement for completed   Your guarantor's financial
 quarter in the current FY.               officer certifies to be
                                          correct.
(iii) Additional information related to  Your guarantor's financial
 bonds, if requested by the Director.     officer certifies to be
                                          correct.
------------------------------------------------------------------------

    (4) Your guarantor's total outstanding and proposed guarantees must 
not exceed 25 percent of its unencumbered domestic net worth.
    (c) Your guarantor must submit an agreement executed by the 
guarantor and all parties bound by the agreement. All parties are bound 
jointly and severally and must meet the qualifications set forth in 
Sec.  585.107.
    (1) When any party is a corporation, two corporate officers 
authorized to execute the guaranty agreement on behalf of the 
corporation must sign the agreement.
    (2) When any party is a partnership, joint venture, or syndicate, 
the guaranty agreement must bind each party who has a beneficial 
interest in your guarantor and provide that, upon BOEM demand under 
your guaranty, each party is jointly and severally liable for 
compliance with all terms and conditions of your lease(s) or grant(s) 
covered by the agreement.
    (3) When forfeiture of the guaranty is called for, the agreement 
must provide that your guarantor will either bring your lease(s) or 
grant(s) into compliance or provide, within 7 days, sufficient funds to 
permit BOEM to complete corrective action.
    (4) The guaranty agreement must contain a confession of judgment, 
providing that, if we determine that you are, or your operator or 
operating rights owner is, in default, the guarantor must not challenge 
the determination and must remedy the default.
    (5) If you fail, or your operator or operating rights owner fails, 
to comply with any law, term, or regulation, your guarantor must either 
take corrective action or provide, within 7 days or other agreed upon 
time period, sufficient funds for BOEM to complete corrective action. 
Such compliance must not reduce your guarantor's liability.
    (6) If your guarantor wants to terminate the period of liability, 
your guarantor must notify you and us at least 90 days before the 
proposed termination date, obtain our approval for termination of all 
or a specified portion of the guarantee for liabilities arising after 
that date, and remain liable for all your work performed during the 
period the agreement is in effect.
    (7) Each guaranty submitted pursuant to this section is deemed to 
contain all the above terms, even if they are not actually in the 
agreement.
    (d) Before the termination of your guaranty, you must provide an 
acceptable replacement in the form of a bond or other security.

Sec.  585.529  Can I use a lease- or grant-specific decommissioning 
account to meet the financial assurance requirements related to 
decommissioning?

    (a) In lieu of a surety bond, BOEM may authorize you to establish a 
lease-, ROW grant-, or RUE grant-specific decommissioning account in a 
federally-insured institution. The funds may not be withdrawn from the 
account without our written approval.
    (1) The funds must be payable to BOEM and pledged to meet your 
lease or grant decommissioning and site clearance obligations; and
    (2) You must fully fund the account within the time BOEM prescribes 
to

[[Page 64754]]

cover all costs of decommissioning including site clearance. BOEM will 
estimate the cost of decommissioning, including site clearance.
    (b) Any interest paid on the account will be treated as account 
funds unless we authorize in writing that any interest be paid to the 
depositor.
    (c) We may allow you to pledge Treasury securities, payable to BOEM 
on demand, to satisfy your obligation to make payments into the 
account. Acceptable Treasury securities and their collateral value are 
determined in accordance with 31 CFR part 203, Collateral Margins Table 
(which can be found at http://www.treasurydirect.gov).
    (d) We may require you to commit a specified stream of revenues as 
payment into the account so that the account will be fully funded, as 
prescribed in paragraph (a)(2) of this section. The commitment may 
include revenue from other operations.

Changes in Financial Assurance

Sec.  585.530  What must I do if my financial assurance lapses?

    (a) If your surety is decertified by the Treasury, becomes bankrupt 
or insolvent, or if your surety's charter or license is suspended or 
revoked, or if any other approved financial assurance expires for any 
reason, you must:
    (1) Inform BOEM within 3 business days about the financial 
assurance lapse; and
    (2) Provide new financial assurance in the amount set by BOEM, as 
provided in this subpart.
    (b) You must notify BOEM within 3 business days after you learn of 
any action filed alleging that you, your surety, or third-party 
guarantor, is insolvent or bankrupt.

Sec.  585.531  What happens if the value of my financial assurance is 
reduced?

    If the value of your financial assurance is reduced below the 
required financial assurance amount because of a default or any other 
reason, you must provide additional financial assurance sufficient to 
meet the requirements of this subpart within 45 days or within a 
different period as specified by BOEM.

Sec.  585.532  What happens if my surety wants to terminate the period 
of liability of my bond?

    (a) Terminating the period of liability of a bond ends the period 
during which surety liability continues to accrue. The surety continues 
to be responsible for obligations and liabilities that accrued during 
the period of liability and before the date on which BOEM terminates 
the period of liability under paragraph (b) of this section. The 
liabilities that accrue during a period of liability include:
    (1) Obligations that started to accrue before the beginning of the 
period of liability and have not been met; and
    (2) Obligations that began accruing during the period of liability.
    (b) Your surety must submit to BOEM its request to terminate the 
period of liability under its bond and notify you of that request. If 
you intend to continue activities, or have not met all obligations of 
your lease or grant, you must provide a replacement bond or alternative 
form of financial assurance of equivalent or greater value. BOEM will 
terminate that period of liability within 90 days after BOEM receives 
the request.

Sec.  585.533  How does my surety obtain cancellation of my bond?

    (a) BOEM will release a bond or allow a surety to cancel a bond, 
and will relieve the surety from accrued obligations only if:
    (1) BOEM determines that there are no outstanding obligations 
covered by the bond; or
    (2) The following occurs:
    (i) BOEM accepts a replacement bond or an alternative form of 
financial assurance in an amount equal to or greater than the bond to 
be cancelled to cover the terminated period of liability;
    (ii) The surety issuing the new bond has expressly agreed to assume 
all outstanding liabilities under the original bond that accrued during 
the period of liability that was terminated; and
    (iii) The surety issuing the new bond has agreed to assume that 
portion of the outstanding liabilities that accrued during the 
terminated period of liability that exceeds the coverage of the bond 
prescribed under Sec. Sec.  585.515, 585.516, 585.520, or 585.521, and 
of which you were notified.
    (b) When your lease or grant ends, your surety(ies) remain(s) 
responsible, and BOEM will retain any financial assurance as follows:
    (1) The period of liability ends when you cease all operations and 
activities under the lease or grant, including decommissioning and site 
clearance;
    (2) Your surety or collateral financial assurance will not be 
released until 7 years after the lease ends, or a longer period as 
necessary to complete any appeals or judicial litigation related to 
your bonded obligation, or for BOEM to determine that all of your 
obligations under the lease or grant have been satisfied; and
    (3) BOEM will reduce the amount of your bond or return a portion of 
your financial assurance if we determine that we need less than the 
full amount of the bond or financial assurance to meet any possible 
future obligations.

Sec.  585.534  When may BOEM cancel my bond?

    When your lease or grant ends, your surety(ies) remain(s) 
responsible, and BOEM will retain any pledged security as shown in the 
following table:

------------------------------------------------------------------------
                                                     Your bond will not
            Bond                  The period of      be released until .
                              liability ends . . .           . .
------------------------------------------------------------------------
(a) Bonds for commercial      When BOEM determines  Seven years after
 leases submitted under Sec.   that you have met     the lease ends, or
   585.515.                    all of your           a longer period as
                               obligations under     necessary to
                               the lease.            complete any
                                                     appeals or judicial
                                                     litigation related
                                                     to your bond
                                                     obligation. BOEM
                                                     will reduce the
                                                     amount of your bond
                                                     or return a portion
                                                     of your security if
                                                     BOEM determines
                                                     that you need less
                                                     than the full
                                                     amount of the bond
                                                     to meet any
                                                     possible future
                                                     obligations.
(b) Supplemental or           When BOEM determines  (1) Seven years
 decommissioning bonds         that you have met     after the lease
 submitted under Sec.          all your              ends, or a longer
 585.516.                      decommissioning,      period as necessary
                               site clearance, and   to complete any
                               other obligations.    appeals or judicial
                                                     litigation related
                                                     to your bond
                                                     obligation. BOEM
                                                     will reduce the
                                                     amount of your bond
                                                     or return a portion
                                                     of your security if
                                                     BOEM determines
                                                     that you need less
                                                     than the full
                                                     amount of the bond
                                                     to meet any
                                                     possible future
                                                     obligations; and

[[Page 64755]]

 
                                                    (2) BOEM determines
                                                     that the potential
                                                     liability resulting
                                                     from any undetected
                                                     noncompliance is
                                                     not greater than
                                                     the amount of the
                                                     lease base bond.
(c) Bonds submitted under     When BOEM determines  Seven years after
 Sec.  Sec.   585.520 and      that you have met     the limited lease,
 585.521 for limited leases,   all of your           ROW, or RUE grant
 ROW grants, or RUE grants.    obligations under     or a longer period
                               the limited lease     as necessary to
                               or grant.             complete any
                                                     appeals or judicial
                                                     litigation related
                                                     to your bond
                                                     obligation. BOEM
                                                     will reduce the
                                                     amount of your bond
                                                     or return a portion
                                                     of your security if
                                                     BOEM determines
                                                     that you need less
                                                     than the full
                                                     amount of the bond
                                                     to meet any
                                                     possible future
                                                     obligations.
------------------------------------------------------------------------

Sec.  585.535  Why might BOEM call for forfeiture of my bond?

    (a) BOEM may call for forfeiture of all or part of the bond, 
pledged security, or other form of guaranty if:
    (1) After notice and demand for performance by BOEM, you refuse or 
fail, within the timeframe we prescribe, to comply with any term or 
condition of your lease or grant, other authorization or approval, or 
applicable regulations; or
    (2) You default on one of the conditions under which we accepted 
your bond.
    (b) We may pursue forfeiture without first making demands for 
performance against any co-lessee or holder of an interest in your ROW 
or RUE, or other person approved to perform obligations under your 
lease or grant.

Sec.  585.536  How will I be notified of a call for forfeiture?

    (a) BOEM will notify you and your surety, including any provider of 
financial assurance, in writing of the call for forfeiture and provide 
the reasons for the forfeiture and the amount to be forfeited. We will 
base the amount upon an estimate of the total cost of corrective action 
to bring your lease or grant into compliance.
    (b) We will advise you and your surety that you may avoid 
forfeiture if, within 10 business days:
    (1) You agree to and demonstrate in writing to BOEM that you will 
bring your lease or grant into compliance within the timeframe we 
prescribe, and you do so; or
    (2) Your surety agrees to and demonstrates that it will bring your 
lease or grant into compliance within the timeframe we prescribe, even 
if the cost of compliance exceeds the face amount of the bond.

Sec.  585.537  How will BOEM proceed once my bond or other security is 
forfeited?

    (a) If BOEM determines that your bond or other security is 
forfeited, we will collect the forfeited amount and use the funds to 
bring your lease or grant(s) into compliance and correct any default.
    (b) If the amount collected under your bond or other security is 
insufficient to pay the full cost of corrective action, BOEM may take 
or direct action to obtain full compliance and recover all costs in 
excess of the forfeited bond from you or any co-lessee or co-grantee.
    (c) If the amount collected under your bond or other security 
exceeds the full cost of corrective action to bring your lease or 
grant(s) into compliance, we will return the excess funds to the party 
from whom the excess was collected.

Sec. Sec.  585.538-585.539  [Reserved]

Revenue Sharing With States

Sec.  585.540  How will BOEM equitably distribute revenues to States?

    (a) BOEM will distribute among the eligible coastal States 27 
percent of the following revenues derived from qualified projects, 
where a qualified project and qualified project area is determined in 
Sec.  585.541 and an eligible State is determined in Sec.  585.542, 
with each term defined in Sec.  585.112. Revenues subject to 
distribution to eligible States include all bonuses, acquisition fees, 
rentals, and operating fees derived from the entire qualified project 
area and associated project easements not limited to revenues 
attributable to the portion of the project area within 3 miles of the 
seaward boundary of a coastal State. The revenues to be shared do not 
include administrative fees such as service fees and those assessed for 
civil penalties and forfeiture of bond or other surety obligations.
    (b) The project area is the area included within a single lease or 
grant. For each qualified project, BOEM will determine and announce the 
project area and its geographic center at the time it grants or issues 
a lease, easement, or right-of-way on the OCS. If a qualified project 
lease or grant's boundaries change significantly due to actions 
pursuant to Sec. Sec.  585.435 or 585.436, BOEM will re-evaluate the 
project area to determine whether the geographic center has changed. If 
it has, BOEM will re-determine State eligibility and shares 
accordingly.
    (c) To determine each eligible State's share of the 27 percent of 
the revenues for a qualified project, BOEM will use the inverse 
distance formula, which apportions shares according to the relative 
proximity of the nearest point on the coastline of each eligible State 
to the geographic center of the qualified project area. If 
Si is equal to the nearest distance from the geographic 
center of the project area to the i = 1, 2, * * * nth eligible State's 
coastline, then eligible State i would be entitled to the fraction 
Fi of the 27-percent aggregate revenue share due to all the 
eligible States according to the formula:

Fi= (1/Si) / ([Sigma]i=1* * 
*n(1/Si)).

Sec.  585.541  What is a qualified project for revenue sharing 
purposes?

    A qualified project for the purpose of revenue sharing with 
eligible coastal States is one authorized under subsection 8(p) of the 
OCS Lands Act, which includes acreage within the area extending 3 
nautical miles seaward of State submerged lands. A qualified project is 
subject to revenue sharing with those States that are eligible for 
revenue sharing under Sec.  585.542. The entire area within a lease or 
grant for the qualified project, excluding project easements, is 
considered the qualified project area.

Sec.  585.542  What makes a State eligible for payment of revenues?

    A State is eligible for payment of revenues if any part of the 
State's coastline is located within 15 miles of the announced 
geographic center of the project area of a qualified project. A State 
is not eligible for revenue sharing if all parts of that State's 
coastline are more than 15 miles from the announced geographic center 
of the qualified project area. This is the case even if the qualified 
project area is located wholly

[[Page 64756]]

or partially within an area extending 3 nautical miles seaward of the 
submerged lands of that State or if there are no States with a 
coastline less than 15 miles from the announced geographic center of 
the qualified project area.

Sec.  585.543  Example of how the inverse distance formula works.

    (a) Assume that the geographic center of the project area lies 12 
miles from the closest coastline point of State A and 4 miles from the 
closest coastline point of State B. BOEM will round dollar shares to 
the nearest whole dollar. The proportional share due each State would 
be calculated as follows:
    (1) State A's share = [(\1/12\) / (\1/12\+\1/4\)] = \1/4\.
    (2) State B's share = [(\1/4\) / (\1/12\+\1/4\)] = \3/4\.
    (b) Therefore, State B would receive a share of revenues that is 
three times as large as that awarded to State A, based on the finding 
that State B's nearest coastline is one-third the distance to the 
geographic center of the qualified project area as compared to State 
A's nearest coastline. Eligible States share the 27 percent of the 
total revenues from the qualified project as mandated under the OCS 
Lands Act. Hence, if the qualified project generates $1,000,000 of 
Federal revenues in a given year, the Federal Government would 
distribute the States' 27-percent share as follows:
    (1) State A's share = $270,000 x \1/4\ = $67,500.
    (2) State B's share = $270,000 x \3/4\ = $202,500.

Subpart F--Plans and Information Requirements

Sec.  585.600  What plans and information must I submit to BOEM before 
I conduct activities on my lease or grant?

    You must submit a SAP, COP, or GAP and receive BOEM approval as set 
forth in the following table:

------------------------------------------------------------------------
                Before you:                           you must:
------------------------------------------------------------------------
(a) conduct any site assessment activities  submit and obtain approval
 on your commercial lease,                   for your SAP according to
                                             Sec.  Sec.   585.605
                                             through 585.613.
(b) conduct any activities pertaining to    submit and obtain approval
 construction of facilities for commercial   for your COP, according to
 operations on your commercial lease,        Sec.  Sec.   585.620
                                             through 585.629.
(c) conduct any activities on your limited  submit and obtain approval
 lease, ROW grant, or RUE grant in any OCS   for your GAP according to
 area,                                       Sec.  Sec.   585.640
                                             through 585.648.
------------------------------------------------------------------------

Sec.  585.601  When am I required to submit my plans to BOEM?

    Your plan submission requirements depend on whether your lease or 
grant was issued competitively or noncompetitively under subpart B or 
subpart C of this part.
    (a) If your lease or grant is issued competitively, you must submit 
your SAP or your GAP within 6 months of issuance.
    (b) If you request that a lease or grant be issued 
noncompetitively, you must submit your SAP or your GAP within 60 days 
after the Director issues a determination that there is no competitive 
interest.
    (c) If you intend to continue your commercial lease with an 
operations term, you must submit a COP, or a FERC license application, 
at least 6 months before the end of your site assessment term.
    (d) You may submit your COP or FERC license application with your 
SAP.
    (1) You must provide sufficient data and information with your COP 
for BOEM to complete the needed reviews and NEPA analysis; and
    (2) BOEM may need to conduct additional reviews, including NEPA 
analysis, if significant new information becomes available after you 
complete your site assessment activities or you revise your COP. As a 
result of the additional reviews, we may require modification of your 
COP.

Sec.  585.602  What records must I maintain?

    Until BOEM releases your financial assurance under Sec.  585.534, 
you must maintain and provide to BOEM, upon request, all data and 
information related to compliance with required terms and conditions of 
your SAP, COP, or GAP.

Sec. Sec.  585.603-585.604   [Reserved]

Site Assessment Plan and Information Requirements for Commercial Leases

Sec.  585.605  What is a Site Assessment Plan (SAP)?

    (a) A SAP describes the activities (e.g., installation of 
meteorological towers, meteorological buoys) you plan to perform for 
the characterization of your commercial lease, including your project 
easement, or to test technology devices.
    (1) Your SAP must describe how you will conduct your resource 
assessment (e.g., meteorological and oceanographic data collection) or 
technology testing activities; and
    (2) BOEM will withhold trade secrets and commercial or financial 
information that is privileged or confidential from public disclosure 
under exemption 4 of the FOIA and as provided in Sec.  585.113.
    (b) Your SAP must include data from:
    (1) Physical characterization surveys (e.g., geological and 
geophysical surveys or hazards surveys); and
    (2) Baseline environmental surveys (e.g., biological or 
archaeological surveys).
    (c) You must receive BOEM approval of your SAP before you can begin 
any of the approved activities on your lease, as provided in Sec.  
585.613.
    (d) If you propose to construct a facility or combination of 
facilities deemed by BOEM to be complex or significant, as provided in 
Sec.  585.613(a)(1), you must also comply with the requirements of 
subpart G of this part and submit your Safety Management System as 
required by Sec.  585.810.

Sec.  585.606  What must I demonstrate in my SAP?

    (a) Your SAP must demonstrate that you have planned and are 
prepared to conduct the proposed site assessment activities in a manner 
that conforms to your responsibilities listed in Sec.  585.105(a) and:
    (1) Conforms to all applicable laws, regulations, and lease 
provisions of your commercial lease;
    (2) Is safe;
    (3) Does not unreasonably interfere with other uses of the OCS, 
including those involved with National security or defense;
    (4) Does not cause undue harm or damage to natural resources; life 
(including human and wildlife); property; the marine, coastal, or human 
environment; or sites, structures, or objects of historical or 
archaeological significance;
    (5) Uses best available and safest technology;
    (6) Uses best management practices; and
    (7) Uses properly trained personnel.

[[Page 64757]]

    (b) You must also demonstrate that your site assessment activities 
will collect the necessary information and data required for your COP, 
as provided in Sec.  585.626(a).

Sec.  585.607  How do I submit my SAP?

    You must submit one paper copy and one electronic version of your 
SAP to BOEM at the address listed in Sec.  585.110(a).

Sec.  585.608  [Reserved]

Sec.  585.609  [Reserved]

Contents of the Site Assessment Plan

Sec.  585.610  What must I include in my SAP?

    Your SAP must include the following information, as applicable.
    (a) For all activities you propose to conduct under your SAP, you 
must provide the following information:

------------------------------------------------------------------------
          Project information                       Including
------------------------------------------------------------------------
(1) Contact information................  The name, address, e-mail
                                          address, and phone number of
                                          an authorized representative.
(2) The site assessment or technology    A discussion of the objectives;
 testing concept.                         description of the proposed
                                          activities, including the
                                          technology you will use; and
                                          proposed schedule from start
                                          to completion.
(3) Designation of operator, if          As provided in Sec.   585.405.
 applicable.
(4) Commercial lease stipulations and    A description of the measures
 compliance.                              you took, or will take, to
                                          satisfy the conditions of any
                                          lease stipulations related to
                                          your proposed activities.
(5) A location plat....................  The surface location and water
                                          depth for all proposed and
                                          existing structures,
                                          facilities, and appurtenances
                                          located both offshore and
                                          onshore.
(6) General structural and project       Information for each type of
 design, fabrication, and installation.   facility associated with your
                                          project.
(7) Deployment activities..............  A description of the safety,
                                          prevention, and environmental
                                          protection features or
                                          measures that you will use.
(8) Your proposed measures for           A description of the measures
 avoiding, minimizing, reducing,          you will use to avoid or
 eliminating, and monitoring              minimize adverse effects and
 environmental impacts.                   any potential incidental take,
                                          before you conduct activities
                                          on your lease, and how you
                                          will mitigate environmental
                                          impacts from your proposed
                                          activities, including a
                                          description of the measures
                                          you will use as required by
                                          subpart H of this part.
(9) CVA nomination, if required........  CVA nominations for reports in
                                          subpart G of this part, as
                                          required by Sec.   585.706, or
                                          a request to waive the CVA
                                          requirement, as required by
                                          Sec.   585.705(c).
(10) Reference information.............  A list of any document or
                                          published source that you cite
                                          as part of your plan. You may
                                          reference information and data
                                          discussed in other plans you
                                          previously submitted or that
                                          are otherwise readily
                                          available to BOEM.
(11) Decommissioning and site clearance  A discussion of methodologies.
 procedures.
(12) Air quality information...........  Information as described in
                                          Sec.   585.659 of this
                                          section.
(13) A listing of all Federal, State,    A statement indicating whether
 and local authorizations or approvals    such authorization or approval
 required to conduct site assessment      has been applied for or
 activities on your lease.                obtained.
(14) A list of agencies and persons      Contact information and issues
 with whom you have communicated, or      discussed.
 with whom you will communicate,
 regarding potential impacts associated
 with your proposed activities.
(15) Financial assurance information...  Statements attesting that the
                                          activities and facilities
                                          proposed in your SAP are or
                                          will be covered by an
                                          appropriate bond or other
                                          approved security, as required
                                          in Sec.  Sec.   585.515 and
                                          585.516.
(16) Other information.................  Additional information as
                                          requested by BOEM.
------------------------------------------------------------------------

     (b) You must provide the results of geophysical and geological 
surveys, hazards surveys, archaeological surveys (if required), and 
baseline collection studies (e.g., biological) with the supporting data 
in your SAP:

------------------------------------------------------------------------
         Information             Report contents          Including
------------------------------------------------------------------------
(1) Geotechnical............  The results from the  A description of all
                               geotechnical survey   relevant seabed and
                               with supporting       engineering data
                               data.                 and information to
                                                     allow for the
                                                     design of the
                                                     foundation for that
                                                     facility. You must
                                                     provide data and
                                                     information to
                                                     depths below which
                                                     the underlying
                                                     conditions will not
                                                     influence the
                                                     integrity or
                                                     performance of the
                                                     structure. This
                                                     could include a
                                                     series of sampling
                                                     locations (borings
                                                     and in situ tests)
                                                     as well as
                                                     laboratory testing
                                                     of soil samples,
                                                     but may consist of
                                                     a minimum of one
                                                     deep boring with
                                                     samples.

[[Page 64758]]

 
(2) Shallow hazards.........  The results from the  A description of
                               shallow hazards       information
                               survey with           sufficient to
                               supporting data.      determine the
                                                     presence of the
                                                     following features
                                                     and their likely
                                                     effects on your
                                                     proposed facility,
                                                     including:
                                                    (i) Shallow faults;
                                                    (ii) Gas seeps or
                                                     shallow gas;
                                                    (ii) Slump blocks or
                                                     slump sediments;
                                                    (iv) Hydrates; and
                                                    (v) Ice scour of
                                                     seabed sediments.
(3) Archaeological resources  The results from the     (i) A description
                               archaeological           of the results
                               survey with              and data from
                               supporting data, if      the
                               required.                archaeological
                                                        survey;
                                                       (ii) A
                                                        description of
                                                        the historic and
                                                        prehistoric
                                                        archaeological
                                                        resources, as
                                                        required by the
                                                        National
                                                        Historic
                                                        Preservation Act
                                                        (NHPA) of 1966,
                                                        as amended.
(4) Geological survey.......  The results from the  A report that
                               geological survey     describes the
                               with supporting       results of a
                               data.                 geological survey
                                                     that includes
                                                     descriptions of:
                                                    (i) Seismic activity
                                                     at your proposed
                                                     site;
                                                    (ii) Fault zones;
                                                    (iii) The
                                                     possibility and
                                                     effects of seabed
                                                     subsidence; and
                                                    (iv) The extent and
                                                     geometry of
                                                     faulting
                                                     attenuation effects
                                                     of geologic
                                                     conditions near
                                                     your site.
(5) Biological survey.......  The results from the  A description of the
                               biological survey     results of a
                               with supporting       biological survey,
                               data.                 including
                                                     descriptions of the
                                                     presence of live
                                                     bottoms; hard
                                                     bottoms;
                                                     topographic
                                                     features; and
                                                     surveys of other
                                                     marine resources
                                                     such as fish
                                                     populations
                                                     (including
                                                     migratory
                                                     populations),
                                                     marine mammals, sea
                                                     turtles, and sea
                                                     birds.
------------------------------------------------------------------------

     (c) If you submit your COP or FERC license application with your 
SAP then:
    (1) You must provide sufficient data and information with your COP 
or FERC license application for BOEM and/or FERC to complete the needed 
reviews and NEPA analysis.
    (2) You may need to revise your COP or FERC license application and 
BOEM and/or FERC may need to conduct additional reviews, including NEPA 
analysis, if new information becomes available after you complete your 
site assessment activities.

Sec.  585.611  What information must I submit with my SAP to assist 
BOEM in complying with NEPA and other relevant laws?

    (a) You must submit with your SAP detailed information to assist 
BOEM in complying with NEPA and other relevant laws, as appropriate. 
For a noncompetitive commercial lease, you must submit a SAP that 
describes those resources, conditions, and activities listed in the 
following table that could be affected by your proposed activities, or 
that could affect the activities proposed in your SAP.
    (b) For competitively issued commercial leases, BOEM will have 
prepared a NEPA document and consistency determination for the lease 
sale and site assessment activities. However, if you submit a SAP that 
shows changes in impacts from those identified in the NEPA document or 
consistency determination prepared for the lease, BOEM may determine 
that your SAP is subject to a new NEPA/CZMA and other relevant Federal 
reviews. In that case, BOEM will notify you of the determination, and 
you must submit a SAP that describes those resources, conditions, and 
activities listed in the following table that could be affected by your 
proposed activities, or that could affect the activities proposed in 
your SAP, including:

------------------------------------------------------------------------
          Type of information                       Including
------------------------------------------------------------------------
(1) Hazard information.................  Meteorology, oceanography,
                                          sediment transport, geology,
                                          and shallow geological or
                                          manmade hazards.
(2) Water quality......................  Turbidity and total suspended
                                          solids from construction.
(3) Biological resources...............  Benthic communities, marine
                                          mammals, sea turtles, coastal
                                          and marine birds, fish and
                                          shellfish, plankton,
                                          seagrasses, and plant life.
(4) Threatened or endangered species...  As required by the Endangered
                                          Species Act (ESA) of 1973 (16
                                          U.S.C. 1531 et seq.).
(5) Sensitive biological resources or    Essential fish habitat,
 habitats.                                refuges, preserves, special
                                          management areas identified in
                                          coastal management programs,
                                          sanctuaries, rookeries, hard
                                          bottom habitat, chemosynthetic
                                          communities, and calving
                                          grounds; barrier islands,
                                          beaches, dunes, and wetlands.
(6) Archaeological resources...........  As required by the NHPA (16
                                          U.S.C. 470 et seq.), as
                                          amended.
(7) Social and economic resources......  Employment, existing offshore
                                          and coastal infrastructure
                                          (including major sources of
                                          supplies, services, energy,
                                          and water), land use,
                                          subsistence resources and
                                          harvest practices, recreation,
                                          recreational and commercial
                                          fishing (including typical
                                          fishing seasons, location, and
                                          type), minority and lower
                                          income groups, coastal zone
                                          management programs, and
                                          viewshed.
(8) Coastal and marine uses............  Military activities, vessel
                                          traffic, and energy and
                                          nonenergy mineral exploration
                                          or development.

[[Page 64759]]

 
(9) Consistency Certification..........  As required by CZMA, as
                                          appropriate:
                                         (i) 15 CFR part 930, subpart D,
                                          for noncompetitive leases;
                                         (ii) 15 CFR part 930, subpart
                                          E, for competitive leases.
(10) Other resources, conditions, and    As identified by BOEM.
 activities.
------------------------------------------------------------------------

Sec.  585.612  How will my SAP be processed for Federal consistency 
under the Coastal Zone Management Act?

    Your SAP will be processed based on how your commercial lease was 
issued:

------------------------------------------------------------------------
 If your commercial lease was
         issued . . .             Your SAP will be handled as follows:
------------------------------------------------------------------------
(a) Competitively............  BOEM will prepare a consistency
                                determination that will cover the lease
                                sale and site assessment activities.
                                However, if you submit a SAP that shows
                                changes in impacts from those identified
                                in the lease sale consistency
                                determination, you may be subject to a
                                new consistency review. In that case,
                                BOEM will notify you of the
                                determination and we will forward to the
                                State CZM agency 1 copy and 1 electronic
                                copy of your SAP, consistency
                                certification, and necessary data and
                                information required under 15 CFR part
                                930, subpart E, after BOEM has
                                determined that all information
                                requirements for the SAP are met and
                                BOEM prepares its NEPA compliance
                                document.
(b) Noncompetitively.........  You will furnish a copy of your SAP,
                                consistency certification, and necessary
                                data and information pursuant to 15 CFR
                                part 930, subpart D, to the State's CZM
                                agency and BOEM at the same time.
------------------------------------------------------------------------

Sec.  585.613  How will BOEM process my SAP?

    (a) BOEM will review your submitted SAP, and additional information 
provided pursuant to Sec.  585.611, to determine if it contains the 
information necessary to conduct our technical and environmental 
reviews.
    (1) We will notify you if we deem your proposed facility or 
combination of facilities to be complex or significant;
    (2) We will notify you if your submitted SAP lacks any necessary 
information;
    (b) BOEM will prepare NEPA analysis, as appropriate.
    (c) As appropriate, we will coordinate and consult with relevant 
Federal and State agencies, executives of relevant local governments, 
and affected Indian Tribes and will provide to other Federal, State, 
and local agencies and affected Indian Tribes relevant nonproprietary 
data and information pertaining to your proposed activities.
    (d) During the review process, we may request additional 
information if we determine that the information provided is not 
sufficient to complete the review and approval process. If you fail to 
provide the requested information, BOEM may disapprove your SAP.
    (e) Upon completion of our technical and environmental reviews and 
other reviews required by Federal laws (e.g., CZMA), BOEM may approve, 
disapprove, or approve with modifications your SAP.
    (1) If we approve your SAP, we will specify terms and conditions to 
be incorporated into your SAP. You must certify compliance with those 
terms and conditions required under Sec.  585.615(c); and
    (2) If we disapprove your SAP, we will inform you of the reasons 
and allow you an opportunity to submit a revised plan making the 
necessary corrections, and may suspend the term of your lease, as 
appropriate, to allow this to occur.

Activities Under an Approved SAP

Sec.  585.614  When may I begin conducting activities under my approved 
SAP?

    (a) You may begin conducting the activities approved in your SAP 
following BOEM approval of your SAP.
    (b) If you are installing a facility or a combination of facilities 
deemed by BOEM to be complex or significant, as provided in Sec.  
585.613(a)(1), you must comply with the requirements of subpart G of 
this part and submit your Safety Management System required by Sec.  
585.810 before construction may begin.

Sec.  585.615  What other reports or notices must I submit to BOEM 
under my approved SAP?

    (a) You must notify BOEM in writing within 30 days of completing 
installation activities approved in your SAP.
    (b) You must prepare and submit to BOEM a report annually on 
November 1 of each year that summarizes your site assessment activities 
and the results of those activities. BOEM will withhold trade secrets 
and commercial or financial information that is privileged or 
confidential from public disclosure under exemption 4 of the FOIA and 
as provided in Sec.  585.113.
    (c) You must submit a certification of compliance annually (or 
other frequency as determined by BOEM) with certain terms and 
conditions of your SAP that BOEM identifies under Sec.  585.613(e)(1). 
Together with your certification, you must submit:
    (1) Summary reports that show compliance with the terms and 
conditions which require certification; and
    (2) A statement identifying and describing any mitigation measures 
and monitoring methods and their effectiveness. If you identified 
measures that were not effective, you must include your recommendations 
for new mitigation measures or monitoring methods.

Sec.  585.616  [Reserved]

Sec.  585.617  What activities require a revision to my SAP, and when 
will BOEM approve the revision?

    (a) You must notify BOEM in writing before conducting any 
activities not described in your approved SAP, describing in detail the 
type of activities you propose to conduct. We will determine whether 
the activities you propose are authorized by your existing SAP or 
require a revision to your SAP. We may request additional information 
from you, if necessary, to make this determination.
    (b) BOEM will periodically review the activities conducted under an 
approved SAP. The frequency and extent of the review will be based on 
the significance

[[Page 64760]]

of any changes in available information and on onshore or offshore 
conditions affecting, or affected by, the activities conducted under 
your SAP. If the review indicates that the SAP should be revised to 
meet the requirements of this part, we will require you to submit the 
needed revisions.
    (c) Activities for which a proposed revision to your SAP will 
likely be necessary include:
    (1) Activities not described in your approved SAP;
    (2) Modifications to the size or type of facility or equipment you 
will use;
    (3) Changes in the surface location of a facility or structure;
    (4) Addition of a facility or structure not contemplated in your 
approved SAP;
    (5) Changes in the location of your onshore support base from one 
State to another, or to a new base requiring expansion;
    (6) Changes in the location of bottom disturbances (anchors, 
chains, etc.) by 500 feet (152 meters) or greater from the approved 
locations. If a specific anchor pattern was approved as a mitigation 
measure to avoid contact with bottom features, any change in the 
proposed bottom disturbances would likely trigger the need for a 
revision;
    (7) Structural failure of one or more facilities; or
    (8) Changes to any other activity specified by BOEM.
    (d) We may begin the appropriate NEPA analysis and other relevant 
consultations when we determine that a proposed revision could:
    (1) Result in a significant change in the impacts previously 
identified and evaluated;
    (2) Require any additional Federal authorizations; or
    (3) Involve activities not previously identified and evaluated.
    (e) When you propose a revision, we may approve the revision if we 
determine that the revision is:
    (1) Designed not to cause undue harm or damage to natural 
resources; life (including human and wildlife); property; the marine, 
coastal, or human environment; or sites, structures, or objects of 
historical or archaeological significance; and
    (2) Otherwise consistent with the provisions of subsection 8(p) of 
the OCS Lands Act.

Sec.  585.618  What must I do upon completion of approved site 
assessment activities?

    (a) If, prior to the expiration of your site assessment term, you 
timely submit a COP meeting the requirements of this subpart, or a 
complete FERC license application, that describes the continued use of 
existing facilities approved in your SAP, you may keep such facilities 
in place on your lease during the time that BOEM reviews your COP for 
approval or FERC reviews your license application for approval.
    (b) You are not required to initiate the decommissioning process 
for facilities that are authorized to remain in place under your 
approved COP or approved FERC license.
    (c) If, following the technical and environmental review of your 
submitted COP, BOEM determines that such facilities may not remain in 
place, you must initiate the decommissioning process, as provided in 
subpart I of this part.
    (d) If FERC determines that such facilities may not remain in 
place, you must initiate the decommissioning process as provided in 
subpart I of this part.
    (e) You must initiate the decommissioning process, as set forth in 
subpart I of this part, upon the termination of your lease.

Sec.  585.619  [Reserved]

Construction and Operations Plan for Commercial Leases

Sec.  585.620  What is a Construction and Operations Plan (COP)?

    The COP describes your construction, operations, and conceptual 
decommissioning plans under your commercial lease, including your 
project easement. BOEM will withhold trade secrets and commercial or 
financial information that is privileged or confidential from public 
disclosure under exemption 4 of the FOIA and in accordance with the 
terms of Sec.  585.113.
    (a) Your COP must describe all planned facilities that you will 
construct and use for your project, including onshore and support 
facilities and all anticipated project easements.
    (b) Your COP must describe all proposed activities including your 
proposed construction activities, commercial operations, and conceptual 
decommissioning plans for all planned facilities, including onshore and 
support facilities.
    (c) You must receive BOEM approval of your COP before you can begin 
any of the approved activities on your lease.

Sec.  585.621  What must I demonstrate in my COP?

    Your COP must demonstrate that you have planned and are prepared to 
conduct the proposed activities in a manner that conforms to your 
responsibilities listed in Sec.  585.105(a) and:
    (a) Conforms to all applicable laws, implementing regulations, 
lease provisions, and stipulations or conditions of your commercial 
lease;
    (b) Is safe;
    (c) Does not unreasonably interfere with other uses of the OCS, 
including those involved with National security or defense;
    (d) Does not cause undue harm or damage to natural resources; life 
(including human and wildlife); property; the marine, coastal, or human 
environment; or sites, structures, or objects of historical or 
archaeological significance;
    (e) Uses best available and safest technology;
    (f) Uses best management practices; and
    (g) Uses properly trained personnel.

Sec.  585.622  How do I submit my COP?

    (a) You must submit one paper copy and one electronic version of 
your COP to BOEM at the address listed in Sec.  585.110(a).
    (b) You may submit information and a request for any project 
easement as part of your original COP submission or as a revision to 
your COP.

Sec. Sec.  585.623 through 585.625  [Reserved]

Contents of the Construction and Operations Plan

Sec.  585.626  What must I include in my COP?

    (a) You must submit the results of the following surveys for the 
proposed site(s) of your facility(ies). Your COP must include the 
following information:

------------------------------------------------------------------------
        Information:            Report contents:         Including:
------------------------------------------------------------------------
(1) Shallow hazards.........  The results of the    Information
                               shallow hazards       sufficient to
                               survey with           determine the
                               supporting data.      presence of the
                                                     following features
                                                     and their likely
                                                     effects on your
                                                     proposed facility,
                                                     including:
                                                       (i) Shallow
                                                        faults;
                                                       (ii) Gas seeps or
                                                        shallow gas;
                                                       (iii) Slump
                                                        blocks or slump
                                                        sediments;

[[Page 64761]]

 
                                                       (iv) Hydrates; or
                                                       (v) Ice scour of
                                                        seabed
                                                        sediments.
(2) Geological survey         The results of the    Assessment of:
 relevant to the design and    geological survey    (i) Seismic activity
 siting of your facility.      with supporting       at your proposed
                               data.                 site;
                                                    (ii) Fault zones;
                                                    (iii) The
                                                     possibility and
                                                     effects of seabed
                                                     subsidence; and
                                                    (iv) The extent and
                                                     geometry of
                                                     faulting
                                                     attenuation effects
                                                     of geologic
                                                     conditions near
                                                     your site.
(3) Biological..............  The results of the    A description of the
                               biological survey     results of
                               with supporting       biological surveys
                               data.                 used to determine
                                                     the presence of
                                                     live bottoms, hard
                                                     bottoms, and
                                                     topographic
                                                     features, and
                                                     surveys of other
                                                     marine resources
                                                     such as fish
                                                     populations
                                                     (including
                                                     migratory
                                                     populations),
                                                     marine mammals, sea
                                                     turtles, and sea
                                                     birds.
(4) Geotechnical survey.....  The results of your   (i) The results of a
                               sediment testing      testing program
                               program with          used to investigate
                               supporting data,      the stratigraphic
                               the various field     and engineering
                               and laboratory test   properties of the
                               methods employed,     sediment that may
                               and the               affect the
                               applicability of      foundations or
                               these methods as      anchoring systems
                               they pertain to the   for your facility.
                               quality of the       (ii) The results of
                               samples, the type     adequate in situ
                               of sediment, and      testing, boring,
                               the anticipated       and sampling at
                               design application.   each foundation
                               You must explain      location, to
                               how the engineering   examine all
                               properties of each    important sediment
                               sediment stratum      and rock strata to
                               affect the design     determine its
                               of your facility.     strength
                               In your               classification,
                               explanation, you      deformation
                               must describe the     properties, and
                               uncertainties         dynamic
                               inherent in your      characteristics.
                               overall testing      (iii) The results of
                               program, and the      a minimum of one
                               reliability and       deep boring (with
                               applicability of      soil sampling and
                               each test method.     testing) at each
                                                     edge of the project
                                                     area and within the
                                                     project area as
                                                     needed to determine
                                                     the vertical and
                                                     lateral variation
                                                     in seabed
                                                     conditions and to
                                                     provide the
                                                     relevant
                                                     geotechnical data
                                                     required for
                                                     design.
(5) Archaeological resources  The results of the    A description of the
                               archaeological        historic and
                               resource survey       prehistoric
                               with supporting       archaeological
                               data.                 resources, as
                                                     required by the
                                                     NHPA (16 U.S.C. 470
                                                     et. seq.), as
                                                     amended.
(6) Overall site              An overall site       An analysis of the
 investigation.                investigation         potential for:
                               report for your      (i) Scouring of the
                               facility that         seabed;
                               integrates the       (ii) Hydraulic
                               findings of your      instability;
                               shallow hazards      (iii) The occurrence
                               surveys and           of sand waves;
                               geologic surveys,    (iv) Instability of
                               and, if required,     slopes at the
                               your subsurface       facility location;
                               surveys with         (v) Liquefaction, or
                               supporting data.      possible reduction
                                                     of sediment
                                                     strength due to
                                                     increased pore
                                                     pressures;
                                                       (vi) Degradation
                                                        of subsea
                                                        permafrost
                                                        layers;
                                                       (vii) Cyclic
                                                        loading;
                                                       (viii) Lateral
                                                        loading;
                                                       (ix) Dynamic
                                                        loading;
                                                       (x) Settlements
                                                        and
                                                        displacements;
                                                       (xi) Plastic
                                                        deformation and
                                                        formation
                                                        collapse
                                                        mechanisms; and
                                                       (xii) Sediment
                                                        reactions on the
                                                        facility
                                                        foundations or
                                                        anchoring
                                                        systems.
------------------------------------------------------------------------

    (b) Your COP must include the following project-specific 
information, as applicable.

------------------------------------------------------------------------
          Project information:                      Including:
------------------------------------------------------------------------
(1) Contact information................  The name, address, e-mail
                                          address, and phone number of
                                          an authorized representative.
(2) Designation of operator, if          As provided in Sec.   585.405.
 applicable.
(3) The construction and operation       A discussion of the objectives,
 concept.                                 description of the proposed
                                          activities, tentative schedule
                                          from start to completion, and
                                          plans for phased development,
                                          as provided in Sec.   585.629.
(4) Commercial lease stipulations and    A description of the measures
 compliance.                              you took, or will take, to
                                          satisfy the conditions of any
                                          lease stipulations related to
                                          your proposed activities.
(5) A location plat....................  The surface location and water
                                          depth for all proposed and
                                          existing structures,
                                          facilities, and appurtenances
                                          located both offshore and
                                          onshore, including all anchor/
                                          mooring data.
(6) General structural and project       Information for each type of
 design, fabrication, and installation.   structure associated with your
                                          project and, unless BOEM
                                          provides otherwise, how you
                                          will use a CVA to review and
                                          verify each stage of the
                                          project.

[[Page 64762]]

 
(7) All cables and pipelines, including  Location, design and
 cables on project easements.             installation methods, testing,
                                          maintenance, repair, safety
                                          devices, exterior corrosion
                                          protection, inspections, and
                                          decommissioning.
(8) A description of the deployment      Safety, prevention, and
 activities.                              environmental protection
                                          features or measures that you
                                          will use.
(9) A list of solid and liquid wastes    Disposal methods and locations.
 generated.
(10) A listing of chemical products      A list of chemical products
 used (if stored volume exceeds           used; the volume stored on
 Environmental Protection Agency (EPA)    location; their treatment,
 Reportable Quantities).                  discharge, or disposal methods
                                          used; and the name and
                                          location of the onshore waste
                                          receiving, treatment, and/or
                                          disposal facility. A
                                          description of how these
                                          products would be brought
                                          onsite, the number of
                                          transfers that may take place,
                                          and the quantity that that
                                          will be transferred each time.
(11) A description of any vessels,       An estimate of the frequency
 vehicles, and aircraft you will use to   and duration of vessel/vehicle/
 support your activities.                 aircraft traffic.
(12) A general description of the        (i) Under normal conditions.
 operating procedures and systems.       (ii) In the case of accidents
                                          or emergencies, including
                                          those that are natural or
                                          manmade.
(13) Decommissioning and site clearance  A discussion of general
 procedures.                              concepts and methodologies.
(14) A listing of all Federal, State,    (i) The U.S. Coast Guard, U.S.
 and local authorizations, approvals,     Army Corps Of Engineers, and
 or permits that are required to          any other applicable
 conduct the proposed activities,         authorizations, approvals, or
 including commercial operations.         permits, including any
                                          Federal, State or local
                                          authorizations pertaining to
                                          energy gathering, transmission
                                          or distribution (e.g.,
                                          interconnection
                                          authorizations).
                                         (ii) A statement indicating
                                          whether you have applied for
                                          or obtained such
                                          authorization, approval, or
                                          permit.
(15) Your proposed measures for          A description of the measures
 avoiding, minimizing, reducing,          you will use to avoid or
 eliminating, and monitoring              minimize adverse effects and
 environmental impacts.                   any potential incidental take
                                          before you conduct activities
                                          on your lease, and how you
                                          will mitigate environmental
                                          impacts from your proposed
                                          activities, including a
                                          description of the measures
                                          you will use as required by
                                          subpart H of this part.
(16) Information you incorporate by      A listing of the documents you
 reference.                               referenced.
(17) A list of agencies and persons      Contact information and issues
 with whom you have communicated, or      discussed.
 with whom you will communicate,
 regarding potential impacts associated
 with your proposed activities.
(18) Reference.........................  A list of any document or
                                          published source that you cite
                                          as part of your plan. You may
                                          reference information and data
                                          discussed in other plans you
                                          previously submitted or that
                                          are otherwise readily
                                          available to BOEM.
(19) Financial assurance...............  Statements attesting that the
                                          activities and facilities
                                          proposed in your COP are or
                                          will be covered by an
                                          appropriate bond or security,
                                          as required by Sec.  Sec.
                                          585.515 and 585.516.
(20) CVA nominations for reports         CVA nominations for reports in
 required in subpart G of this part.      subpart G of this part, as
                                          required by Sec.   585.706, or
                                          a request for a waiver under
                                          Sec.   585.705(c).
(21) Construction schedule.............  A reasonable schedule of
                                          construction activity showing
                                          significant milestones leading
                                          to the commencement of
                                          commercial operations.
(22) Air quality information...........  As described in Sec.   585.659
                                          of this section.
(23) Other information.................  Additional information as
                                          required by BOEM.
------------------------------------------------------------------------

Sec.  585.627  What information and certifications must I submit with 
my COP to assist the BOEM in complying with NEPA and other relevant 
laws?

    (a) You must submit with your COP detailed information to assist 
BOEM in complying with NEPA and other relevant laws. Your COP must 
describe those resources, conditions, and activities listed in the 
following table that could be affected by your proposed activities, or 
that could affect the activities proposed in your COP, including:

------------------------------------------------------------------------
          Type of information:                      Including:
------------------------------------------------------------------------
(1) Hazard information.................  Meteorology, oceanography,
                                          sediment transport, geology,
                                          and shallow geological or
                                          manmade hazards.
(2) Water quality......................  Turbidity and total suspended
                                          solids from construction.
(3) Biological resources...............  Benthic communities, marine
                                          mammals, sea turtles, coastal
                                          and marine birds, fish and
                                          shellfish, plankton,
                                          seagrasses, and plant life.
(4) Threatened or endangered species...  As defined by the ESA (16
                                          U.S.C. 1531 et seq.).
(5) Sensitive biological resources or    Essential fish habitat,
 habitats.                                refuges, preserves, special
                                          management areas identified in
                                          coastal management programs,
                                          sanctuaries, rookeries, hard
                                          bottom habitat, chemosynthetic
                                          communities, and calving
                                          grounds; barrier islands,
                                          beaches, dunes, and wetlands.
(6) Archaeological resources...........  As required by the NHPA (16
                                          U.S.C. 470 et seq.), as
                                          amended.

[[Page 64763]]

 
(7) Social and economic resources......  Employment, existing offshore
                                          and coastal infrastructure
                                          (including major sources of
                                          supplies, services, energy,
                                          and water), land use,
                                          subsistence resources and
                                          harvest practices, recreation,
                                          recreational and commercial
                                          fishing (including typical
                                          fishing seasons, location, and
                                          type), minority and lower
                                          income groups, coastal zone
                                          management programs, and
                                          viewshed.
(8) Coastal and marine uses............  Military activities, vessel
                                          traffic, and energy and
                                          nonenergy mineral exploration
                                          or development.
(9) Consistency Certification..........  As required by the CZMA:
                                            (i) 15 CFR part 930, subpart
                                             D, for noncompetitive
                                             leases.
                                            (ii) 15 CFR part 930,
                                             subpart E, for competitive
                                             leases.
(10) Other resources, conditions, and    As identified by BOEM.
 activities.
------------------------------------------------------------------------

     (b) You must submit one paper copy and one electronic copy of your 
consistency certification. Your consistency certification must include:
    (1) One copy of your consistency certification under subsection 
307(c)(3)(B) of the CZMA (16 U.S.C. 1456(c)(3)(B)) and 15 CFR 930.76 
stating that the proposed activities described in detail in your plans 
comply with the State(s) approved coastal management program(s) and 
will be conducted in a manner that is consistent with such program(s); 
and
    (2) ``Information,'' as required by 15 CFR 930.76(a) and 15 CFR 
930.58(a)(2), and ``Analysis,'' as required by 15 CFR 930.58(a)(3).
    (c) You must submit your oil spill response plan, as required by 30 
CFR part 254.
    (d) You must submit your Safety Management System as required by 
Sec.  585.810.

Sec.  585.628  How will BOEM process my COP?

    (a) BOEM will review your submitted COP, and the information 
provided pursuant to Sec.  585.627, to determine if it contains all the 
required information necessary to conduct our technical and 
environmental reviews. We will notify you if your submitted COP lacks 
any necessary information.
    (b) BOEM will prepare an appropriate NEPA analysis.
    (c) BOEM will forward one copy of your COP, consistency 
certification, and associated data and information under the CZMA to 
the State's CZM agency after all information requirements for the COP 
are met.
    (d) As appropriate, BOEM will coordinate and consult with relevant 
Federal, State, and local agencies and affected Indian Tribes, and 
provide to them relevant nonproprietary data and information pertaining 
to your proposed activities.
    (e) During the review process, we may request additional 
information if we determine that the information provided is not 
sufficient to complete the review and approval process. If you fail to 
provide the requested information, BOEM may disapprove your COP.
    (f) Upon completion of our technical and environmental reviews and 
other reviews required by Federal law (e.g., CZMA), BOEM may approve, 
disapprove, or approve with modifications your COP.
    (1) If we approve your COP, we will specify terms and conditions to 
be incorporated into your COP. You must certify compliance with certain 
of those terms and conditions, as required under Sec.  585.633(b); and
    (2) If we disapprove your COP, we will inform you of the reasons 
and allow you an opportunity to resubmit a revised plan addressing the 
concerns identified, and may suspend the term of your lease, as 
appropriate, to allow this to occur.
    (g) If BOEM approves your project easement, BOEM will issue an 
addendum to your lease specifying the terms of the project easement. A 
project easement may include off-lease areas that:
    (1) Contain the sites on which cable, pipeline, or associated 
facilities are located;
    (2) Do not exceed 200 feet (61 meters) in width, unless safety and 
environmental factors during construction and maintenance of the 
associated cables or pipelines require a greater width; and
    (3) For associated facilities, are limited to the area reasonably 
necessary for power or pumping stations or other accessory facilities.

Sec.  585.629  May I develop my lease in phases?

    In your COP, you may request development of your commercial lease 
in phases. In support of your request, you must provide details as to 
what portions of the lease will be initially developed for commercial 
operations and what portions of the lease will be reserved for 
subsequent phased development.

Sec.  585.630  [Reserved]

Activities Under an Approved COP

Sec.  585.631  When must I initiate activities under an approved COP?

    After your COP is approved, you must commence construction by the 
date given in the construction schedule required by Sec.  
585.626(b)(21), and included as a part of your approved COP, unless 
BOEM approves a deviation from your schedule.

Sec.  585.632  What documents must I submit before I may construct and 
install facilities under my approved COP?

    (a) You must submit to BOEM the documents listed in the following 
table:

------------------------------------------------------------------------
                                                        Requirements are
                      Document:                            found in:
------------------------------------------------------------------------
(1) Facility Design Report...........................     Sec.   585.701
(2) Fabrication and Installation Report..............     Sec.   585.702
------------------------------------------------------------------------

     (b) You must submit your Safety Management System, as required by 
Sec.  585.810 of this part.
    (c) These activities must fall within the scope of your approved 
COP. If they do not fall within the scope of your approved COP, you 
will be required to submit a revision to your COP, under Sec.  585.634, 
for BOEM approval before commencing the activity.

Sec.  585.633  How do I comply with my COP?

    (a) Based on BOEM's environmental and technical reviews, we will 
specify terms and conditions to be incorporated into your COP.
    (b) You must submit a certification of compliance annually (or 
other frequency as determined by BOEM) with certain terms and 
conditions of your COP that BOEM identifies. Together with your 
certification, you must submit:
    (1) Summary reports that show compliance with the terms and 
conditions which require certification; and
    (2) A statement identifying and describing any mitigation measures 
and

[[Page 64764]]

monitoring methods, and their effectiveness. If you identified measures 
that were not effective, then you must make recommendations for new 
mitigation measures or monitoring methods.
    (c) As provided at Sec.  585.105(i), BOEM may require you to submit 
any supporting data and information.

Sec.  585.634  What activities require a revision to my COP, and when 
will BOEM approve the revision?

    (a) You must notify BOEM in writing before conducting any 
activities not described in your approved COP, describing in detail the 
type of activities you propose to conduct. We will determine whether 
the activities you propose are authorized by your existing COP or 
require a revision to your COP. We may request additional information 
from you, if necessary, to make this determination.
    (b) BOEM will periodically review the activities conducted under an 
approved COP. The frequency and extent of the review will be based on 
the significance of any changes in available information, and on 
onshore or offshore conditions affecting, or affected by, the 
activities conducted under your COP. If the review indicates that the 
COP should be revised to meet the requirement of this part, we will 
require you to submit the needed revisions.
    (c) Activities for which a proposed revision to your COP will 
likely be necessary include:
    (1) Activities not described in your approved COP;
    (2) Modifications to the size or type of facility or equipment you 
will use;
    (3) Change in the surface location of a facility or structure;
    (4) Addition of a facility or structure not described in your 
approved COP;
    (5) Change in the location of your onshore support base from one 
State to another or to a new base requiring expansion;
    (6) Changes in the location of bottom disturbances (anchors, 
chains, etc.) by 500 feet (152 meters) or greater from the approved 
locations (e.g., if a specific anchor pattern was approved as a 
mitigation measure to avoid contact with bottom features, any change in 
the proposed bottom disturbances would likely trigger the need for a 
revision);
    (7) Structural failure of one or more facilities; or
    (8) Change in any other activity specified by BOEM.
    (d) We may begin the appropriate NEPA analysis and relevant 
consultations when we determine that a proposed revision could:
    (1) Result in a significant change in the impacts previously 
identified and evaluated;
    (2) Require any additional Federal authorizations; or
    (3) Involve activities not previously identified and evaluated.
    (e) When you propose a revision, we may approve the revision if we 
determine that the revision is:
    (1) Designed not to cause undue harm or damage to natural 
resources; life (including human and wildlife); property; the marine, 
coastal, or human environment; or sites, structures, or objects of 
historical or archaeological significance; and
    (2) Otherwise consistent with the provisions of subsection 8(p) of 
the OCS Lands Act.

Sec.  585.635  What must I do if I cease activities approved in my COP 
before the end of my commercial lease?

    You must notify the BOEM, within 5 business days, any time you 
cease commercial operations, without an approved suspension, under your 
approved COP. If you cease commercial operations for an indefinite 
period which extends longer than 6 months, we may cancel your lease 
under Sec.  585.437 and, you must initiate the decommissioning process 
as set forth in subpart I of this part.

Sec.  585.636  What notices must I provide BOEM following approval of 
my COP?

    You must notify BOEM in writing of the following events, within the 
time periods provided:
    (a) No later than 30 days after commencing activities associated 
with the placement of facilities on the lease area under a Fabrication 
and Installation Report.
    (b) No later than 30 days after completion of construction and 
installation activities under a Fabrication and Installation Report.
    (c) At least 7 days before commencing commercial operations.

Sec.  585.637  When may I commence commercial operations on my 
commercial lease?

    If you are conducting activities on your lease that:
    (a) Do not require a FERC license (i.e., wind), then you may 
commence commercial operations 30 days after the CVA or project 
engineer has submitted to BOEM the final Fabrication and Installation 
Report for the fabrication and installation review, as provided in 
Sec.  585.708.
    (b) Require a FERC license or exemption, then you may commence 
commercial operations when permitted by the terms of your license or 
exemption.

Sec.  585.638  What must I do upon completion of my commercial 
operations as approved in my COP or FERC license?

    (a) Upon completion of your approved activities under your COP, you 
must initiate the decommissioning process as set forth in subpart I of 
this part. You must submit your decommissioning application as provided 
in Sec. Sec.  585.905 and 585.906.
    (b) Upon completion of your approved activities under your FERC 
license, the terms of your FERC license will govern your 
decommissioning activities.

Sec.  585.639  [Reserved]

General Activities Plan Requirements For Limited Leases, ROW Grants, 
and RUE Grants

Sec.  585.640  What is a General Activities Plan (GAP)?

    (a) A GAP describes your proposed construction, activities, and 
conceptual decommissioning plans for all planned facilities, including 
testing of technology devices and onshore and support facilities that 
you will construct and use for your project, including any project 
easements for the assessment and development of your limited lease or 
grant.
    (b) You must receive BOEM approval of your GAP before you can begin 
any of the approved activities on your lease or grant. For a ROW grant 
or RUE grant issued competitively, you must submit your GAP within 6 
months of issuance.

Sec.  585.641  What must I demonstrate in my GAP?

    Your GAP must demonstrate that you have planned and are prepared to 
conduct the proposed activities in a manner that:
    (a) Conforms to all applicable laws, implementing regulations, 
lease provisions and stipulations;
    (b) Is safe;
    (c) Does not unreasonably interfere with other uses of the OCS, 
including those involved with National security or defense;
    (d) Does not cause undue harm or damage to natural resources; life 
(including human and wildlife); property; the marine, coastal, or human 
environment; or sites, structures, or objects of historical or 
archaeological significance;
    (e) Uses best available and safest technology;
    (f) Uses best management practices; and
    (g) Uses properly trained personnel.

[[Page 64765]]

Sec.  585.642  How do I submit my GAP?

    (a) You must submit one paper copy and one electronic version of 
your GAP to BOEM at the address listed in Sec.  585.110(a).
    (b) If you have a limited lease, you may submit information on any 
project easement as part of your original GAP submission or as a 
revision to your GAP.

Sec.  585.643  [Reserved]

Sec.  585.644  [Reserved]

Contents of the General Activities Plan

Sec.  585.645  What must I include in my GAP?

    (a) You must provide the following results of geophysical and 
geological surveys, hazards surveys, archaeological surveys (if 
required), and baseline collection studies (e.g., biological) with the 
supporting data in your GAP:

------------------------------------------------------------------------
        Information:            Report contents:         Including:
------------------------------------------------------------------------
(1) Geotechnical............  The results from the  A description of all
                               geotechnical survey   relevant seabed and
                               with supporting       engineering data
                               data.                 and information to
                                                     allow for the
                                                     design of the
                                                     foundation for that
                                                     facility. You must
                                                     provide data and
                                                     information to
                                                     depths below which
                                                     the underlying
                                                     conditions will not
                                                     influence the
                                                     integrity or
                                                     performance of the
                                                     structure. This
                                                     could include a
                                                     series of sampling
                                                     locations (borings
                                                     and in situ tests)
                                                     as well as
                                                     laboratory testing
                                                     of soil samples,
                                                     but may consist of
                                                     a minimum of one
                                                     deep boring with
                                                     samples.
(2) Shallow hazards.........  The results from the  A description of
                               shallow hazards       information
                               survey with           sufficient to
                               supporting data.      determine the
                                                     presence of the
                                                     following features
                                                     and their likely
                                                     effects on your
                                                     proposed facility,
                                                     including:
                                                       (i) Shallow
                                                        faults;
                                                       (ii) Gas seeps or
                                                        shallow gas;
                                                       (iii) Slump
                                                        blocks or slump
                                                        sediments;
                                                       (iv) Hydrates; or
                                                       (v) Ice scour of
                                                        seabed
                                                        sediments.
(3) Archaeological resources  The results from the  (i) A description of
                               archaeological        the results and
                               survey with           data from the
                               supporting data, if   archaeological
                               required.             survey;
                                                       (ii) A
                                                        description of
                                                        the historic and
                                                        prehistoric
                                                        archaeological
                                                        resources, as
                                                        required by NHPA
                                                        (16 U.S.C. 470
                                                        et seq.), as
                                                        amended.
(4) Geological survey.......  The results from the  A report that
                               geological survey     describes the
                               with supporting       results of a
                               data.                 geological survey
                                                     that includes
                                                     descriptions of:
                                                       (i) Seismic
                                                        activity at your
                                                        proposed site;
                                                       (ii) Fault zones;
                                                       (iii) The
                                                        possibility and
                                                        effects of
                                                        seabed
                                                        subsidence; and
                                                       (iv) The extent
                                                        and geometry of
                                                        faulting
                                                        attenuation
                                                        effects of
                                                        geologic
                                                        conditions near
                                                        your site.
(5) Biological survey.......  The results from the  A description of the
                               biological survey     results of a
                               with supporting       biological survey,
                               data.                 including the
                                                     presence of live
                                                     bottoms, hard
                                                     bottoms, and
                                                     topographic
                                                     features, and
                                                     surveys of other
                                                     marine resources
                                                     such as fish
                                                     populations
                                                     (including
                                                     migratory
                                                     populations),
                                                     marine mammals, sea
                                                     turtles, and sea
                                                     birds.
------------------------------------------------------------------------

     (b) For all activities you propose to conduct under your GAP, you 
must provide the following information:

------------------------------------------------------------------------
          Project information:                      Including:
------------------------------------------------------------------------
(1) Contact information................  The name, address, e-mail
                                          address, and phone number of
                                          an authorized representative.
(2) The site assessment or technology    A discussion of the objectives;
 testing concept.                         description of the proposed
                                          activities, including the
                                          technology you will use; and
                                          proposed schedule from start
                                          to completion.
(3) Designation of operator, if          As provided in Sec.   585.405.
 applicable.
(4) ROW, RUE or limited lease grant      A description of the measures
 stipulations, if known.                  you took, or will take, to
                                          satisfy the conditions of any
                                          lease stipulations related to
                                          your proposed activities.
(5) A location plat....................  The surface location and water
                                          depth for all proposed and
                                          existing structures,
                                          facilities, and appurtenances
                                          located both offshore and
                                          onshore.
(6) General structural and project       Information for each type of
 design, fabrication, and installation.   facility associated with your
                                          project.
(7) Deployment activities..............  A description of the safety,
                                          prevention, and environmental
                                          protection features or
                                          measures that you will use.
(8) A list of solid and liquid wastes    Disposal methods and locations.
 generated.

[[Page 64766]]

 
(9) A listing of chemical products used  A list of chemical products
 (only if stored volume exceeds USEPA     used; the volume stored on
 Reportable Quantities).                  location; their treatment,
                                          discharge, or disposal methods
                                          used; and the name and
                                          location of the onshore waste
                                          receiving, treatment, and/or
                                          disposal facility. A
                                          description of how these
                                          products would be brought
                                          onsite, the number of
                                          transfers that may take place,
                                          and the quantity that will be
                                          transferred each time.
(10) Reference information.............  A list of any document or
                                          published source that you cite
                                          as part of your plan. You may
                                          reference information and data
                                          discussed in other plans you
                                          previously submitted or that
                                          are otherwise readily
                                          available to BOEM.
(11) Decommissioning and site clearance  A discussion of methodologies.
 procedures.
(12) Air quality information...........  As described in Sec.   585.659
                                          of this section.
(13) A listing of all Federal, State,    A statement indicating whether
 and local authorizations or approvals    such authorization or approval
 required to conduct site assessment      has been applied for or
 activities on your lease.                obtained.
(14) A list of agencies and persons      Contact information and issues
 with whom you have communicated, or      discussed.
 with whom you will communicate,
 regarding potential impacts associated
 with your proposed activities.
(15) Financial assurance information...  Statements attesting that the
                                          activities and facilities
                                          proposed in your GAP are or
                                          will be covered by an
                                          appropriate bond or other
                                          approved security, as required
                                          in Sec.  Sec.   585.520 and
                                          585.521.
(16) Other information.................  Additional information as
                                          requested by BOEM.
------------------------------------------------------------------------

     (c) If you are applying for a project easement or constructing a 
facility, or a combination of facilities deemed by BOEM to be complex 
or significant, you must provide the following information in addition 
to what is required in paragraphs (a) and (b) of this section and 
comply with the requirements of subpart G of this part:

------------------------------------------------------------------------
          Project information:                      Including:
------------------------------------------------------------------------
(1) The construction and operation       A discussion of the objectives,
 concept.                                 description of the proposed
                                          activities, and tentative
                                          schedule from start to
                                          completion.
(2) All cables and pipelines, including  The location, design,
 cables on project easements.             installation methods, testing,
                                          maintenance, repair, safety
                                          devices, exterior corrosion
                                          protection, inspections, and
                                          decommissioning.
(3) A description of the deployment      Safety, prevention, and
 activities.                              environmental protection
                                          features or measures that you
                                          will use.
(4) A general description of the         (i) Under normal conditions.
 operating procedures and systems.       (ii) In the case of accidents
                                          or emergencies, including
                                          those that are natural or
                                          manmade.
(5) CVA nominations for reports          CVA nominations for reports in
 required in subpart G of this part.      subpart G of this part, as
                                          required by Sec.   585.706, or
                                          a request for a waiver under
                                          Sec.   585.705(c).
(6) Construction schedule..............  A reasonable schedule of
                                          construction activity showing
                                          significant milestones leading
                                          to the commencement of
                                          activities.
(7) Other information..................  Additional information as
                                          required by the BOEM.
------------------------------------------------------------------------

     (d) BOEM will withhold trade secrets and commercial or financial 
information that is privileged or confidential from public disclosure 
in accordance with the terms of Sec.  585.113.

Sec.  585.646  What information and certifications must I submit with 
my GAP to assist BOEM in complying with NEPA and other relevant laws?

    You must submit with your GAP detailed information to assist BOEM 
in complying with NEPA and other relevant laws. Your GAP must describe 
those resources, conditions, and activities listed in the following 
table that could be affected by your proposed activities, or that could 
affect the activities proposed in your GAP, including:

------------------------------------------------------------------------
          Type of information:                      Including:
------------------------------------------------------------------------
(a) Hazard information.................  Meteorology, oceanography,
                                          sediment transport, geology,
                                          and shallow geological or
                                          manmade hazards.
(b) Water quality......................  Turbidity and total suspended
                                          solids from construction.
(c) Biological resources...............  Benthic communities, marine
                                          mammals, sea turtles, coastal
                                          and marine birds, fish and
                                          shellfish, plankton,
                                          seagrasses, and plant life.
(d) Threatened or endangered species...  As required by the ESA (16
                                          U.S.C. 1531 et seq.).
(e) Sensitive biological resources or    Essential fish habitat,
 habitats.                                refuges, preserves, special
                                          management areas identified in
                                          coastal management programs,
                                          sanctuaries, rookeries, hard
                                          bottom habitat, chemosynthetic
                                          communities, and calving
                                          grounds; barrier islands,
                                          beaches, dunes, and wetlands.
(f) Archaeological resources...........  As required by NHPA (16 U.S.C.
                                          470 et seq.), as amended.

[[Page 64767]]

 
(g) Social and economic resources......  Employment, existing offshore
                                          and coastal infrastructure
                                          (including major sources of
                                          supplies, services, energy,
                                          and water), land use,
                                          subsistence resources and
                                          harvest practices, recreation,
                                          recreational and commercial
                                          fishing (including typical
                                          fishing seasons, location, and
                                          type), minority and lower
                                          income groups, coastal zone
                                          management programs, and
                                          viewshed.
(h) Coastal and marine uses............  Military activities, vessel
                                          traffic, and energy and
                                          nonenergy mineral exploration
                                          or development.
(i) Consistency Certification..........  As required by CZMA:
                                            (1) 15 CFR part 930, subpart
                                             D, for noncompetitive
                                             leases;
                                            (2) 15 CFR part 930, subpart
                                             E, for competitive leases.
(j) Other resources, conditions, and     As required by BOEM.
 activities.
------------------------------------------------------------------------

Sec.  585.647  How will my GAP be processed for Federal consistency 
under the Coastal Zone Management Act?

    Your GAP will be processed based on how your limited lease, ROW 
grant, or RUE grant was issued:

----------------------------------------------------------------------------------------------------------------
If your limited lease, ROW, or RUE grant was issued:
                                                                Your GAP will be processed as follows:
----------------------------------------------------------------------------------------------------------------
(a) Competitively,                                    BOEM will forward one paper copy and one electronic copy
                                                       of your GAP, consistency certification, and necessary
                                                       data and information required under 15 CFR part 930,
                                                       subpart E, after BOEM has determined that all information
                                                       requirements for the GAP are met and BOEM prepares its
                                                       NEPA compliance document.
(b) Noncompetitively,                                 You will furnish a copy of your GAP, consistency
                                                       certification, and necessary data and information
                                                       pursuant to 15 CFR part 930, subpart D, to the State's
                                                       CZM agency and BOEM at the same time.
----------------------------------------------------------------------------------------------------------------

Sec.  585.648  How will BOEM process my GAP?

    (a) BOEM will review your submitted GAP, along with the information 
and certifications provided pursuant to Sec.  585.646, to determine if 
it contains all the required information necessary to conduct our 
technical and environmental reviews.
    (1) We will notify you if we deem your proposed facility or 
combination of facilities to be complex or significant; and
    (2) We will notify you if your submitted GAP lacks any necessary 
information.
    (b) BOEM will prepare appropriate NEPA analysis.
    (c) When appropriate, we will coordinate and consult with relevant 
State and Federal agencies and affected Indian Tribes and provide to 
other local, State, and Federal agencies and affected Indian Tribes 
relevant nonproprietary data and information pertaining to your 
proposed activities.
    (d) During the review process, we may request additional 
information if we determine that the information provided is not 
sufficient to complete the review and approval process. If you fail to 
provide the requested information, BOEM may disapprove your GAP.
    (e) Upon completion of our technical and environmental reviews and 
other reviews required by Federal law (e.g., CZMA), BOEM may approve, 
disapprove, or approve with modifications your GAP.
    (1) If we approve your GAP, we will specify terms and conditions to 
be incorporated into your GAP. You must certify compliance with certain 
of those terms and conditions, as required under Sec.  585.653(c); and
    (2) If we disapprove your GAP, we will inform you of the reasons 
and allow you an opportunity to resubmit a revised plan making the 
necessary corrections, and may suspend the term of your lease or grant, 
as appropriate, to allow this to occur.

Sec.  585.649  [Reserved]

Activities Under an Approved GAP

Sec.  585.650  When may I begin conducting activities under my GAP?

    After BOEM approves your GAP, you may begin conducting the approved 
activities that do not involve a project easement or the construction 
of facilities on the OCS that BOEM has deemed to be complex or 
significant.

Sec.  585.651  When may I construct complex or significant OCS 
facilities on my limited lease or any facilities on my project easement 
proposed under my GAP?

    If you are applying for a project easement, or installing a 
facility or a combination of facilities on your limited lease deemed by 
BOEM to be complex or significant, as provided in Sec.  585.648(a)(1), 
you also must comply with the requirements of subpart G of this part 
and submit your Safety Management System description required by Sec.  
585.810 before construction may begin.

Sec.  585.652  How long do I have to conduct activities under an 
approved GAP?

    After BOEM approves your GAP, you have:
    (a) For a limited lease, 5 years to conduct your approved 
activities, unless we renew the term under Sec. Sec.  585.425 through 
585.429.
    (b) For a ROW grant or RUE grant, the time provided in the terms of 
the grant.

Sec.  585.653  What other reports or notices must I submit to BOEM 
under my approved GAP?

    (a) You must notify BOEM in writing within 30 days after completing 
installation activities approved in your GAP.
    (b) You must prepare and submit to BOEM annually a report that 
summarizes the findings from any activities you conduct under your 
approved GAP and the results of those activities. We will protect the 
information from public disclosure as provided in Sec.  585.113.

[[Page 64768]]

    (c) You must annually (or other frequency as determined by BOEM) 
submit a certification of compliance with those terms and conditions of 
your GAP that BOEM identifies under Sec.  585.648(e)(1). Together with 
your certification, you must submit:
    (1) Summary reports that show compliance with the terms and 
conditions which require certification; and
    (2) A statement identifying and describing any mitigation measures 
and monitoring methods and their effectiveness. If you identified 
measures that were not effective, you must include your recommendations 
for new mitigation measures or monitoring methods.

Sec.  585.654  [Reserved]

Sec.  585.655  What activities require a revision to my GAP, and when 
will BOEM approve the revision?

    (a) You must notify BOEM in writing before conducting any 
activities not described in your approved GAP, describing in detail the 
type of activities you propose to conduct. We will determine whether 
the activities you propose are authorized by your existing GAP or 
require a revision to your GAP. We may request additional information 
from you, if necessary, to make this determination.
    (b) BOEM will periodically review the activities conducted under an 
approved GAP. The frequency and extent of the review will be based on 
the significance of any changes in available information and on onshore 
or offshore conditions affecting, or affected by, the activities 
conducted under your GAP. If the review indicates that the GAP should 
be revised to meet the requirement of this part, we will require you to 
submit the needed revisions.
    (c) Activities for which a proposed revision to your GAP will 
likely be necessary include:
    (1) Activities not described in your approved GAP;
    (2) Modifications to the size or type of facility or equipment you 
will use;
    (3) Change in the surface location of a facility or structure;
    (4) Addition of a facility or structure not contemplated in your 
approved GAP;
    (5) Change in the location of your onshore support base from one 
State to another or to a new base requiring expansion;
    (6) Changes in the locations of bottom disturbances (anchors, 
chains, etc.) by 500 feet (152 meters) or greater from the approved 
locations. If a specific anchor pattern was approved as a mitigation 
measure to avoid contact with bottom features, any change in the 
proposed bottom disturbances would likely trigger the need for a 
revision;
    (7) Structural failure of one or more facilities; or
    (8) Change to any other activity specified by BOEM.
    (d) We may begin the appropriate NEPA analysis and any relevant 
consultations when we determine that a proposed revision could:
    (1) Result in a significant change in the impacts previously 
identified and evaluated;
    (2) Require any additional Federal authorizations; or
    (3) Involve activities not previously identified and evaluated.
    (e) When you propose a revision, we may approve the revision if we 
determine that the revision is:
    (1) Designed not to cause undue harm or damage to natural 
resources; life (including human and wildlife); property; the marine, 
coastal, or human environment; or sites, structures, or objects of 
historical or archaeological significance; and
    (2) Otherwise consistent with the provisions of subsection 8(p) of 
the OCS Lands Act.

Sec.  585.656  What must I do if I cease activities approved in my GAP 
before the end of my term?

    You must notify the BOEM any time you cease activities under your 
approved GAP without an approved suspension. If you cease activities 
for an indefinite period that exceeds 6 months, BOEM may cancel your 
lease or grant under Sec.  585.437, as applicable, and you must 
initiate the decommissioning process, as set forth in subpart I of this 
part.

Sec.  585.657  What must I do upon completion of approved activities 
under my GAP?

    Upon completion of your approved activities under your GAP, you 
must initiate the decommissioning process as set forth in subpart I of 
this part. You must submit your decommissioning application as provided 
in Sec. Sec.  585.905 and 585.906.

Cable and Pipeline Deviations

Sec.  585.658  Can my cable or pipeline construction deviate from my 
approved COP or GAP?

    (a) You must make every effort to ensure that all cables and 
pipelines are constructed in a manner that minimizes deviations from 
the approved plan under your lease or grant.
    (b) If BOEM determines that a significant change in conditions has 
occurred that would necessitate an adjustment to your ROW, RUE or lease 
before the commencement of construction of the cable or pipeline on the 
grant or lease, BOEM will consider modifications to your ROW grant, RUE 
grant, or your lease addendum for a project easement in connection with 
your COP or GAP.
    (c) If, after construction, it is determined that a deviation from 
the approved plan has occurred, you must:
    (1) Notify the operators of all leases (including mineral leases 
issued under this subchapter) and holders of all ROW grants or RUE 
grants (including all grants issued under this subchapter) which 
include the area where a deviation has occurred and provide BOEM with 
evidence of such notification;
    (2) Relinquish any unused portion of your lease or grant; and
    (3) Submit a revised plan for BOEM approval as necessary.
    (d) Construction of a cable or pipeline that substantially deviates 
from the approved plan may be grounds for cancellation of the lease or 
grant.

Sec.  585.659  What requirements must I include in my SAP, COP, or GAP 
regarding air quality?

    (a) You must comply with the Clean Air Act (42 U.S.C. 7409) and its 
implementing regulations, according to the following table.

------------------------------------------------------------------------
    If your project is located . . .              you must . . .
------------------------------------------------------------------------
(1) in the Gulf of Mexico west of        include in your plan any
 87.5[deg] west longitude (western Gulf   information required for BOEM
 of Mexico).                              to make the appropriate air
                                          quality determinations for
                                          your project.
(2) anywhere else on the OCS...........  follow the appropriate
                                          implementing regulations as
                                          promulgated by the EPA under
                                          40 CFR part 55.
------------------------------------------------------------------------

[[Page 64769]]

    (b) For air quality modeling that you perform in support of the 
activities proposed in your plan, you should contact the appropriate 
regulatory agency to establish a modeling protocol to ensure that the 
agency's needs are met and that the meteorological files used are 
acceptable before initiating the modeling work. In the western Gulf of 
Mexico (west of 87.5[deg] west longitude), you must submit to BOEM 
three copies of the modeling report and three sets of digital files as 
supporting information. The digital files must contain the formatted 
meteorological files used in the modeling runs, the model input file, 
and the model output file.

Subpart G--Facility Design, Fabrication, and Installation

Reports

Sec.  585.700  What reports must I submit to BOEM before installing 
facilities described in my approved SAP, COP, or GAP?

    (a) You must submit the following reports to BOEM before installing 
facilities described in your approved COP (Sec.  585.632(a)) and, when 
required by this part, your SAP (Sec.  585.614(b)) or GAP (Sec.  
585.651):
    (1) A Facility Design Report; and
    (2) A Fabrication and Installation Report.
    (b) You may begin to fabricate and install the approved facilities 
after BOEM notifies you that it has received your reports and has no 
objections. If BOEM receives the reports, but does not respond with 
objections within 60 days of receipt or 60 days after we approve your 
SAP, COP, or GAP, if you submitted your report with the plan, BOEM is 
deemed not to have objections to the reports, and you may commence 
fabrication and installation of your facility or facilities.
    (c) If BOEM has any objections, we will notify you verbally or in 
writing within 60 days of receipt of the report. Following initial 
notification of objections, BOEM may follow up with written 
correspondence outlining its specific objections to the report and 
request that certain actions be undertaken. You cannot commence 
activities addressed in such report until you resolve all objections to 
BOEM's satisfaction.

Sec.  585.701  What must I include in my Facility Design Report?

    (a) Your Facility Design Report provides specific details of the 
design of any facilities, including cables and pipelines that are 
outlined in your approved SAP, COP, or GAP. Your Facility Design Report 
must demonstrate that your design conforms to your responsibilities 
listed in Sec.  585.105(a). You must include the following items in 
your Facility Design Report:

------------------------------------------------------------------------
     Required documents         Required contents    Other requirements
------------------------------------------------------------------------
(1) Cover letter............  (i) Proposed          You must submit 1
                               facility              paper copy and 1
                               designations;         electronic copy.
                              (ii) Lease, ROW
                               grant or RUE grant
                               number;.
                              (iii) Area; name and
                               block numbers; and.
                              (iv) The type of
                               facility..
(2) Location plat...........  (i) Latitude and      Your plat must be
                               longitude             drawn to a scale of
                               coordinates,          1 inch equals 100
                               Universal Mercator    feet and include
                               grid-system           the coordinates of
                               coordinates, state    the lease, ROW
                               plane coordinates     grant, or RUE grant
                               in the Lambert or     block boundary
                               Transverse Mercator   lines. You must
                               Projection System;    submit 1 paper copy
                              (ii) Distances in      and 1 electronic
                               feet from the         copy.
                               nearest block
                               lines. These
                               coordinates must be
                               based on the NAD
                               (North American
                               Datum) 83 datum
                               plane coordinate
                               system; and.
                              (iii) The location
                               of any proposed
                               project easement..
(3) Front, Side, and Plan     (i) Facility          Your drawing sizes
 View drawings.                dimensions and        must not exceed
                               orientation;          11'' x 17''. You
                              (ii) Elevations        must submit 1 paper
                               relative to Mean      copy and 1
                               Lower Low Water;      electronic copy.
                               and.
                              (iii) Pile sizes and
                               penetration..
(4) 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 1 paper
                               submitted             copy and 1
                               including, e.g.,      electronic copy.
                              (i) Cathodic
                               protection systems;.
                              (ii) Jacket design;.
                              (iii) Pile
                               foundations;.
                              (iv) Mooring and
                               tethering systems;.
                              (v) Foundations and
                               anchoring systems;
                               and.
                              (vi) Associated
                               cable and pipeline
                               designs..
(5) Summary of environmental  A summary of the      You must submit 1
 data used for design.         environmental data    paper copy and 1
                               used in the design    electronic copy. If
                               or analysis of the    you submitted these
                               facility. Examples    data as part of
                               of relevant data      your SAP, COP, or
                               include information   GAP, you may
                               on:                   reference the plan.
                              (i) Extreme weather;
                              (ii) Seafloor
                               conditions; and.
                              (iii) Waves, wind,
                               current, tides,
                               temperature, snow
                               and ice effects,
                               marine growth, and
                               water depth..

[[Page 64770]]

 
(6) Summary of the            (i) Loading           You must submit 1
 engineering design data.      information (e.g.,    paper copy and 1
                               live, dead,           electronic copy.
                               environmental);
                              (ii) Structural
                               information (e.g.,
                               design-life;
                               material types;
                               cathodic protection
                               systems; design
                               criteria; fatigue
                               life; jacket
                               design; deck
                               design; production
                               component design;
                               foundation pilings
                               and templates, and
                               mooring or
                               tethering systems;
                               fabrication and
                               installation
                               guidelines); and.
                              (iii) Location of
                               foundation
                               boreholes and
                               foundation piles;
                               and.
                              (iv) Foundation
                               information (e.g.,
                               soil stability,
                               design criteria)..
(7) A complete set of design  Self-explanatory....  You must submit 1
 calculations.                                       paper copy and 1
                                                     electronic copy.
(8) Project-specific studies  All studies           You must submit 1
 used in the facility design   pertinent to          paper copy and 1
 or installation.              facility design or    electronic copy.
                               installation, e.g.,
                               oceanographic and
                               soil reports
                               including the
                               results of the
                               surveys required in
                               Sec.  Sec.
                               585.610(b),
                               585.627(a), or
                               585.645(a).
(9) Description of the loads  (i) Loads imposed by  You must submit 1
 imposed on the facility.      jacket;               paper copy and 1
                              (ii) Decks;.........   electronic copy.
                              (iii) Production
                               components;.
                              (iv) Foundations,
                               foundation pilings
                               and templates, and
                               anchoring systems;
                               and.
                              (v) Mooring or
                               tethering systems..
(10) Geotechnical Report....  A list of all data    You must submit 1
                               from borings and      paper copy and 1
                               recommended design    electronic copy.
                               parameters.
------------------------------------------------------------------------

     (b) For any floating facility, your design must meet the 
requirements of the U.S. Coast Guard for structural integrity and 
stability (e.g., verification of center of gravity). The design must 
also consider:
    (1) Foundations, foundation pilings and templates, and anchoring 
systems; and
    (2) Mooring or tethering systems.
    (c) You must provide the location of records, as required in Sec.  
585.714(c).
    (d) If you are required to use a CVA, the Facility Design Report 
must include one paper copy of the following certification statement: 
``The design of this structure has been certified by a BOEM approved 
CVA to be in accordance with accepted engineering practices and the 
approved SAP, GAP, or COP as appropriate. The certified design and as-
built plans and specifications will be on file at (given location).''
    (e) BOEM will withhold trade secrets and commercial or financial 
information that is privileged or confidential from public disclosure 
under exemption 4 of the FOIA and in accordance with the terms of Sec.  
585.113.

Sec.  585.702  What must I include in my Fabrication and Installation 
Report?

    (a) Your Fabrication and Installation Report must describe how your 
facilities will be fabricated and installed in accordance with the 
design criteria identified in the Facility Design Report; your approved 
SAP, COP, or GAP; and generally accepted industry standards and 
practices. Your Fabrication and Installation Report must demonstrate 
how your facilities will be fabricated and installed in a manner that 
conforms to your responsibilities listed in Sec.  585.105(a). You must 
include the following items in your Fabrication and Installation 
Report:

------------------------------------------------------------------------
     Required documents         Required contents    Other requirements
------------------------------------------------------------------------
(1) Cover letter............  (i) Proposed          You must submit 1
                               facility              paper copy and 1
                               designation, lease,   electronic copy.
                               ROW grant, or RUE
                               grant number;
                              (ii) Area, name, and
                               block number; and.
                              (iii) The type of
                               facility..
(2) Schedule................  Fabrication and       You must submit 1
                               installation.         paper copy and 1
                                                     electronic copy.
(3) Fabrication information.  The industry          You must submit 1
                               standards you will    paper copy and 1
                               use to ensure the     electronic copy.
                               facilities are
                               fabricated to the
                               design criteria
                               identified in your
                               Facility Design
                               Report.
(4) Installation process      Details associated    You must submit 1
 information.                  with the deployment   paper copy and 1
                               activities,           electronic copy.
                               equipment, and
                               materials,
                               including onshore
                               and offshore
                               equipment and
                               support, and
                               anchoring and
                               mooring patterns.
(5) Federal, State, and       Either 1 copy of the  You must submit 1
 local permits (e.g., EPA,     permit or             paper copy and 1
 Army Corps of Engineers).     information on the    electronic copy.
                               status of the
                               application.
(6) Environmental             (i) Water discharge;  You must submit 1
 information.                 (ii) Waste disposal;   paper copy and 1
                              (iii) Vessel           electronic copy. If
                               information; and.     you submitted these
                              (iv) Onshore waste     data as part of
                               receiving treatment   your SAP, COP, or
                               or disposal           GAP, you may
                               facilities..          reference the plan.

[[Page 64771]]

 
(7) Project easement........  Design of any         You must submit 1
                               cables, pipelines,    paper copy and 1
                               or facilities.        electronic copy.
                               Information on
                               burial methods and
                               vessels.
------------------------------------------------------------------------

    (b) You must provide the location of records, as required in Sec.  
585.714(c).
    (c) If you are required to use a CVA, the Fabrication and 
Installation Report must include one paper copy of the following 
certification statement: ``The fabrication and installation of this 
structure has been certified by a BOEM approved CVA to be in accordance 
with accepted engineering practices and the approved SAP, GAP, or COP 
as appropriate. The certified design and as-built plans and 
specifications will be on file at (given location).''
    (d) BOEM will withhold trade secrets and commercial or financial 
information that is privileged or confidential from public disclosure 
under exemption 4 of the FOIA and in accordance with the terms of Sec.  
585.113.

Sec.  585.703  What reports must I submit for project modifications and 
repairs?

    (a) You must verify and, in a report to us, certify that major 
repairs and major modifications to the project conform to accepted 
engineering practices.
    (1) A major repair is a corrective action involving structural 
members affecting the structural integrity of a portion of or all the 
facility.
    (2) A major modification is an alteration involving structural 
members affecting the structural integrity of a portion of or all the 
facility.
    (b) The report must also identify the location of all records 
pertaining to the major repairs or major modifications, as required in 
Sec.  585.714(c).
    (c) BOEM may require you to use a CVA for project modifications and 
repairs.

Sec.  585.704  [Reserved]

Certified Verification Agent

Sec.  585.705  When must I use a Certified Verification Agent (CVA)?

    You must use a CVA to review and certify the Facility Design 
Report, the Fabrication and Installation Report, and the Project 
Modifications and Repairs Report.
    (a) You must use a CVA to:
    (1) Ensure that your facilities are designed, fabricated, and 
installed in conformance with accepted engineering practices and the 
Facility Design Report and Fabrication and Installation Report;
    (2) Ensure that repairs and major modifications are completed in 
conformance with accepted engineering practices; and
    (3) Provide BOEM immediate reports of all incidents that affect the 
design, fabrication, and installation of the project and its 
components.
    (b) BOEM may waive the requirement that you use a CVA if you can 
demonstrate the following:

------------------------------------------------------------------------
                                             Then BOEM may waive the
     If you demonstrate that . . .        requirement for a CVA for the
                                                    following:
------------------------------------------------------------------------
(1) The facility design conforms to a    The design of your
 standard design that has been used       structure(s).
 successfully in a similar environment,
 and the installation design conforms
 to accepted engineering practices.
(2) The manufacturer has successfully    The fabrication of your
 manufactured similar facilities, and     structure(s).
 the facility will be fabricated in
 conformance with accepted engineering
 practices.
(3) The installation company has         The installation of your
 successfully installed similar           structure(s).
 facilities in a similar offshore
 environment, and your structure(s)
 will be installed in conformance with
 accepted engineering practices.
(4) Repairs and major modifications      The repair or major
 will be completed in conformance with    modification of your
 accepted engineering practices.          structure(s).
------------------------------------------------------------------------

    (c) You must submit a request to waive the requirement to use a CVA 
to BOEM in writing, along with your SAP under Sec.  585.610(a)(9), COP 
under Sec.  585.626(b)(20), or GAP under Sec.  585.645(c)(5).
    (1) BOEM will review your request to waive the use of the CVA and 
notify you of our decision along with our decision on your SAP, COP, or 
GAP.
    (2) If BOEM does not waive the requirement for a CVA, you may file 
an appeal under Sec.  585.118.
    (3) If BOEM waives the requirement that you use a CVA, your project 
engineer must perform the same duties and responsibilities as the CVA, 
except as otherwise provided.

Sec.  585.706  How do I nominate a CVA for BOEM approval?

    (a) As part of your COP (as provided in Sec.  585.626(b)(20) and, 
when required by this part, your SAP (Sec.  585.610(a)(9)) or GAP 
(Sec.  585.645(c)(5)), you must nominate a CVA for BOEM approval. You 
must specify whether the nomination is for the Facility Design Report, 
Fabrication and Installation Report, Modification and Repair Report, or 
for any combination of these.
    (b) For each CVA that you nominate, you must submit to BOEM a list 
of documents used in your design that you will forward to the CVA and a 
qualification statement that includes the following:
    (1) Previous experience in third-party verification or experience 
in the design, fabrication, installation, or major modification of 
offshore energy facilities;
    (2) Technical capabilities of the individual or the primary staff 
for the specific project;
    (3) Size and type of organization or corporation;
    (4) In-house availability of, or access to, appropriate technology 
(including computer programs, hardware, and testing materials and 
equipment);
    (5) Ability to perform the CVA functions for the specific project 
considering current commitments;
    (6) Previous experience with BOEM requirements and procedures, if 
any; and
    (7) The level of work to be performed by the CVA.
    (c) Individuals or organizations acting as CVAs must not function 
in any capacity that will create a conflict of

[[Page 64772]]

interest, or the appearance of a conflict of interest.
    (d) The verification must be conducted by or under the direct 
supervision of registered professional engineers.
    (e) BOEM will approve or disapprove your CVA as part of its review 
of the COP or, when required, of your SAP or GAP.
    (f) You must nominate a new CVA for BOEM approval if the previously 
approved CVA:
    (1) Is no longer able to serve in a CVA capacity for the project; 
or
    (2) No longer meets the requirements for a CVA set forth in this 
subpart.

Sec.  585.707  What are the CVA's primary duties for facility design 
review?

    If you are required to use a CVA:
    (a) The CVA must use good engineering judgment and practices in 
conducting an independent assessment of the design of the facility. The 
CVA must certify in the Facility Design Report to BOEM that the 
facility is designed to withstand the environmental and functional load 
conditions appropriate for the intended service life at the proposed 
location.
    (b) The CVA must conduct an independent assessment of all proposed:
    (1) Planning criteria;
    (2) Operational requirements;
    (3) Environmental loading data;
    (4) Load determinations;
    (5) Stress analyses;
    (6) Material designations;
    (7) Soil and foundation conditions;
    (8) Safety factors; and
    (9) Other pertinent parameters of the proposed design.
    (c) For any floating facility, the CVA must ensure that any 
requirements of the U.S. Coast Guard for structural integrity and 
stability (e.g., verification of center of gravity), have been met. The 
CVA must also consider:
    (1) Foundations, foundation pilings and templates, and anchoring 
systems; and
    (2) Mooring or tethering systems.

Sec.  585.708  What are the CVA's or project engineer's primary duties 
for fabrication and installation review?

    (a) The CVA or project engineer must do all of the following:
    (1) Use good engineering judgment and practice in conducting an 
independent assessment of the fabrication and installation activities;
    (2) Monitor the fabrication and installation of the facility as 
required by paragraph (b) of this section;
    (3) Make periodic onsite inspections while fabrication is in 
progress and verify the items required by Sec.  585.709;
    (4) Make periodic onsite inspections while installation is in 
progress and satisfy the requirements of Sec.  585.710; and
    (5) Certify in a report that project components are fabricated and 
installed in accordance with accepted engineering practices; your 
approved COP, SAP, or GAP (as applicable); and the Fabrication and 
Installation Report.
    (i) The report must also identify the location of all records 
pertaining to fabrication and installation, as required in Sec.  
585.714(c); and
    (ii) You may commence commercial operations or other approved 
activities 30 days after BOEM receives that certification report, 
unless BOEM notifies you within that time period of its objections to 
the certification report.
    (b) To comply with paragraph (a)(5) of this section, the CVA or 
project engineer must monitor the fabrication and installation of the 
facility to ensure that it has been built and installed according to 
the Facility Design Report and Fabrication and Installation Report.
    (1) If the CVA or project engineer finds that fabrication and 
installation procedures have been changed or design specifications have 
been modified, the CVA or project engineer must inform you; and
    (2) If you accept the modifications, then you must also inform 
BOEM.

Sec.  585.709  When conducting onsite fabrication inspections, what 
must the CVA or project engineer verify?

    (a) To comply with Sec.  585.708(a)(3), the CVA or project engineer 
must make periodic onsite inspections while fabrication is in progress 
and must verify the following fabrication items, as appropriate:
    (1) Quality control by lessee (or grant holder) and builder;
    (2) Fabrication site facilities;
    (3) Material quality and identification methods;
    (4) Fabrication procedures specified in the Fabrication and 
Installation Report, and adherence to such procedures;
    (5) Welder and welding procedure qualification and identification;
    (6) Structural tolerances specified, and adherence to those 
tolerances;
    (7) Nondestructive examination requirements and evaluation results 
of the specified examinations;
    (8) Destructive testing requirements and results;
    (9) Repair procedures;
    (10) Installation of corrosion-protection systems and splash-zone 
protection;
    (11) Erection procedures to ensure that overstressing of structural 
members does not occur;
    (12) Alignment procedures;
    (13) Dimensional check of the overall structure, including any 
turrets, turret-and-hull interfaces, any mooring line and chain and 
riser tensioning line segments; and
    (14) Status of quality-control records at various stages of 
fabrication.
    (b) For any floating facilities, the CVA or project engineer must 
ensure that any requirements of the U.S. Coast Guard for structural 
integrity and stability (e.g., verification of center of gravity) have 
been met. The CVA or project engineer must also consider:
    (1) Foundations, foundation pilings and templates, and anchoring 
systems; and
    (2) Mooring or tethering systems.

Sec.  585.710  When conducting onsite installation inspections, what 
must the CVA or project engineer do?

    To comply with Sec.  585.708(a)(4), the CVA or project engineer 
must make periodic onsite inspections while installation is in progress 
and must, as appropriate, verify, witness, survey, or check, the 
installation items required by this section.
    (a) The CVA or project engineer must verify, as appropriate, all of 
the following:
    (1) Loadout and initial flotation procedures;
    (2) Towing operation procedures to the specified location, and 
review the towing records;
    (3) Launching and uprighting activities;
    (4) Submergence activities;
    (5) Pile or anchor installations;
    (6) Installation of mooring and tethering systems;
    (7) Final deck and component installations; and
    (8) Installation at the approved location according to the Facility 
Design Report and the Fabrication and Installation Report.
    (b) For a fixed or floating facility, the CVA or project engineer 
must verify that proper procedures were used during the following:
    (1) The loadout of the jacket, decks, piles, or structures from 
each fabrication site; and
    (2) The actual installation of the facility or major modification 
and the related installation activities.
    (c) For a floating facility, the CVA or project engineer must 
verify that proper procedures were used during the following:
    (1) The loadout of the facility;
    (2) The installation of foundation pilings and templates, and 
anchoring systems; and
    (3) The installation of the mooring and tethering systems.

[[Page 64773]]

    (d) The CVA or project engineer must conduct an onsite survey of 
the facility after transportation to the approved location.
    (e) The CVA or project engineer must spot-check the equipment, 
procedures, and recordkeeping as necessary to determine compliance with 
the applicable documents incorporated by reference and the regulations 
under this part.

Sec.  585.711  [Reserved]

Sec.  585.712  What are the CVA's or project engineer's reporting 
requirements?

    (a) The CVA or project engineer must prepare and submit to you and 
BOEM all reports required by this subpart. The CVA or project engineer 
must also submit interim reports to you and BOEM, as requested by the 
BOEM.
    (b) For each report required by this subpart, the CVA or project 
engineer must submit one electronic copy and one paper copy of each 
final report to BOEM. In each report, the CVA or project engineer must:
    (1) Give details of how, by whom, and when the CVA or project 
engineer activities were conducted;
    (2) Describe the CVA's or project engineer's activities during the 
verification process;
    (3) Summarize the CVA's or project engineer's findings; and
    (4) Provide any additional comments that the CVA or project 
engineer deems necessary.

Sec.  585.713  What must I do after the CVA or project engineer 
confirms conformance with the Fabrication and Installation Report on my 
commercial lease?

    After the CVA or project engineer files the certification report, 
you must notify BOEM within 10 business days after commencing 
commercial operations.

Sec.  585.714  What records relating to SAPs, COPs, and GAPs must I 
keep?

    (a) Until BOEM releases your financial assurance under Sec.  
585.534, you must compile, retain, and make available to BOEM 
representatives, within the time specified by BOEM, all of the 
following:
    (1) The as-built drawings;
    (2) The design assumptions and analyses;
    (3) A summary of the fabrication and installation examination 
records;
    (4) The inspection results from the inspections and assessments 
required by Sec. Sec.  585.820 through 585.825; and
    (5) Records of repairs not covered in the inspection report 
submitted under Sec.  585.824(b)(3).
    (b) You must record and retain the original material test results 
of all primary structural materials during all stages of construction 
until BOEM releases your financial assurance under Sec.  585.534. 
Primary material is material that, should it fail, would lead to a 
significant reduction in facility safety, structural reliability, or 
operating capabilities. Items such as steel brackets, deck stiffeners 
and secondary braces or beams would not generally be considered primary 
structural members (or materials).
    (c) You must provide BOEM with the location of these records in the 
certification statement, as required in Sec. Sec.  585.701(c), 
585.703(b), and 585.708(a)(5)(i).

Subpart H--Environmental and Safety Management, Inspections, and 
Facility Assessments for Activities Conducted Under SAPs, COPs and 
GAPs

Sec.  585.800  How must I conduct my activities to comply with safety 
and environmental requirements?

    (a) You must conduct all activities on your lease or grant under 
this part in a manner that conforms with your responsibilities in Sec.  
585.105(a), and using:
    (1) Trained personnel; and
    (2) Technologies, precautions, and techniques that will not cause 
undue harm or damage to natural resources, including their physical, 
atmospheric, and biological components.
    (b) You must certify compliance with those terms and conditions 
identified in your approved SAP, COP, or GAP, as required under 
Sec. Sec.  585.615(c), 585.633(b), or 585.653(c).

Sec.  585.801  How must I conduct my approved activities to protect 
marine mammals, threatened and endangered species, and designated 
critical habitat?

    (a) You must not conduct any activity under your lease or grant 
that may affect threatened or endangered species or that may affect 
designated critical habitat of such species until the appropriate level 
of consultation is conducted, as required under the ESA, as amended (16 
U.S.C. 1531 et seq.), to ensure that your actions are not likely to 
jeopardize a threatened or endangered species and are not likely to 
destroy or adversely modify designated critical habitat.
    (b) You must not conduct any activity under your lease or grant 
that may result in an incidental taking of marine mammals until the 
appropriate authorization has been issued under the Marine Mammal 
Protection Act of 1972 (MMPA) as amended (16 U.S.C. 1361 et seq.).
    (c) If there is reason to believe that a threatened or endangered 
species may be present while you conduct your BOEM approved activities 
or may be affected by the direct or indirect effects of your actions:
    (1) You must notify us that endangered or threatened species may be 
present in the vicinity of the lease or grant or may be affected by 
your actions; and
    (2) We will consult with appropriate State and Federal fish and 
wildlife agencies and, after consultation, shall identify whether, and 
under what conditions, you may proceed.
    (d) If there is reason to believe that designated critical habitat 
of a threatened or endangered species may be affected by the direct or 
indirect effects of your BOEM approved activities:
    (1) You must notify us that designated critical habitat of a 
threatened or endangered species in the vicinity of the lease or grant 
may be affected by your actions; and
    (2) We will consult with appropriate State and Federal fish and 
wildlife agencies and, after consultation, shall identify whether, and 
under what conditions, you may proceed.
    (e) If there is reason to believe that marine mammals may be 
incidentally taken as a result of your proposed activities:
    (1) You must agree to secure an authorization from National Oceanic 
and Atmospheric Administration (NOAA) or the U.S. Fish and Wildlife 
Service (FWS) for incidental taking, including taking by harassment, 
that may result from your actions; and
    (2) You must comply with all measures required by the NOAA or FWS, 
including measures to affect the least practicable impact on such 
species and its habitat and to ensure no immitigable adverse impact on 
the availability of the species for subsistence use.
    (f) Submit to us:
    (1) Measures designed to avoid or minimize adverse effects and any 
potential incidental take of the endangered or threatened species or 
marine mammals;
    (2) Measures designed to avoid likely adverse modification or 
destruction of designated critical habitat of such endangered or 
threatened species; and
    (3) Your agreement to monitor for the incidental take of the 
species and adverse effects on the critical habitat, and provide the 
results of the monitoring to BOEM as required; and
    (4) Your agreement to perform any relevant terms and conditions of 
the Incidental Take Statement that may result from the ESA 
consultation.

[[Page 64774]]

    (5) Your agreement to perform any relevant mitigation measures 
under an MMPA incidental take authorization.

Sec.  585.802  What must I do if I discover a potential archaeological 
resource while conducting my approved activities?

    (a) If you, your subcontractors, or any agent acting on your behalf 
discovers a potential archaeological resource while conducting 
construction activities, or any other activity related to your project, 
you must:
    (1) Immediately halt all seafloor-disturbing activities within the 
area of the discovery;
    (2) Notify BOEM of the discovery within 72 hours; and
    (3) Keep the location of the discovery confidential and not take 
any action that may adversely affect the archaeological resource until 
we have made an evaluation and instructed you on how to proceed.
    (b) We may require you to conduct additional investigations to 
determine if the resource is eligible for listing in the National 
Register of Historic Places under 36 CFR 60.4. We will do this if:
    (1) The site has been impacted by your project activities; or
    (2) Impacts to the site or to the area of potential effect cannot 
be avoided.
    (c) If investigations under paragraph (b) of this section indicate 
that the resource is potentially eligible for listing in the National 
Register of Historic Places, we will tell you how to protect the 
resource, or how to mitigate adverse effects to the site.
    (d) If we incur costs in protecting the resource, under section 
110(g) of the NHPA, we may charge you reasonable costs for carrying out 
preservation responsibilities under the OCS Lands Act.

Sec.  585.803  How must I conduct my approved activities to protect 
essential fish habitats identified and described under the Magnuson-
Stevens Fishery Conservation and Management Act?

    (a) If, during the conduct of your approved activities, BOEM finds 
that essential fish habitat or habitat areas of particular concern may 
be adversely affected by your activities, BOEM must consult with 
National Marine Fisheries Service.
    (b) Any conservation recommendations adopted by BOEM to avoid or 
minimize adverse affects on Essential Fish Habitat will be incorporated 
as terms and conditions in the lease and must be adhered to by the 
applicant. BOEM may require additional surveys to define boundaries and 
avoidance distances.
    (c) If required, BOEM will specify the survey methods and 
instrumentations for conducting the biological survey and will specify 
the contents of the biological report.

Sec. Sec.  585.804-585.809   [Reserved]

Safety Management Systems

Sec.  585.810  What must I include in my Safety Management System?

    You must submit a description of the Safety Management System you 
will use with your COP (provided under Sec.  585.627(d)) and, when 
required by this part, your SAP (as provided in Sec.  585.614(b)) or 
GAP (as provided in Sec.  585.651). You must describe:
    (a) How you will ensure the safety of personnel or anyone on or 
near your facilities;
    (b) Remote monitoring, control, and shut down capabilities;
    (c) Emergency response procedures;
    (d) Fire suppression equipment, if needed;
    (e) How and when you will test your Safety Management System; and
    (f) How you will ensure personnel who operate your facilities are 
properly trained.

Sec.  585.811  When must I follow my Safety Management System?

    Your Safety Management System must be fully functional when you 
begin activities described in your approved COP, SAP, or GAP. You must 
conduct all activities described in your approved COP, SAP, or GAP in 
accordance with the Safety Management System you described, as required 
by Sec.  585.810.

Sec.  585.812  [Reserved]

Maintenance and Shutdowns

Sec.  585.813  When do I have to report removing equipment from 
service?

    (a) The removal of any equipment from service may result in BOEM 
applying remedies, as provided in this part, when such equipment is 
necessary for implementing your approved plan. Such remedies may 
include an order from BOEM requiring you to replace or remove such 
equipment or facilities.
    (b)(1) You must report within 24 hours when equipment necessary for 
implementing your approved plan is removed from service for more than 
12 hours. If you provide an oral notification, you must submit a 
written confirmation of this notice within 3 business days, as required 
by Sec.  585.105(c);
    (2) You do not have to report removing equipment necessary for 
implementing your plan if the removal is part of planned maintenance or 
repair activities; and
    (3) You must notify BOEM when you return the equipment to service.

Sec.  585.814  [Reserved]

Equipment Failure and Adverse Environmental Effects

Sec.  585.815  What must I do if I have facility damage or an equipment 
failure?

    (a) If you have facility damage or the failure of a pipeline, 
cable, or other equipment necessary for you to implement your approved 
plan, you must make repairs as soon as practicable. If you have a major 
repair, you must submit a report of the repairs to BOEM, as required in 
Sec.  585.711.
    (b) If you are required to report any facility damage or failure 
under Sec.  585.831, BOEM may require you to revise your SAP, COP, or 
GAP to describe how you will address the facility damage or failure as 
required by Sec.  585.634 (COP), Sec.  585.617 (SAP), Sec.  585.655 
(GAP). You must submit a report of the repairs to BOEM, as required in 
Sec.  585.703.
    (c) BOEM may require that you analyze cable, pipeline, or facility 
damage or failure to determine the cause. If requested by BOEM, you 
must submit a comprehensive written report of the failure or damage to 
BOEM as soon as available.

Sec.  585.816  What must I do if environmental or other conditions 
adversely affect a cable, pipeline, or facility?

    If environmental or other conditions adversely affect a cable, 
pipeline, or facility so as to endanger the safety or the environment, 
you must:
    (a) Submit a plan of corrective action to BOEM within 30 days of 
the discovery of the adverse effect.
    (b) Take remedial action as described in your corrective action 
plan.
    (c) Submit to the BOEM a report of the remedial action taken within 
30 days after completion.

Sec. Sec.  585.817-585.819   [Reserved]

Inspections and Assessment

Sec.  585.820  Will BOEM conduct inspections?

    BOEM will inspect OCS facilities and any vessels engaged in 
activities authorized under this part. We conduct these inspections:
    (a) To verify that you are conducting activities in compliance with 
subsection 8(p) of the OCS Lands Act; the regulations in this part; the 
terms, conditions, and stipulations of your lease or grant; approved 
plans; and other applicable laws and regulations.
    (b) To determine whether proper safety equipment has been installed 
and is operating properly according to your Safety Management System, 
as required in Sec.  585.810.

[[Page 64775]]

Sec.  585.821  Will BOEM conduct scheduled and unscheduled inspections?

    BOEM will conduct both scheduled and unscheduled inspections.

Sec.  585.822  What must I do when BOEM conducts an inspection?

    (a) When BOEM conducts an inspection, you must:
    (1) Provide access to all facilities on your lease (including your 
project easement) or grant; and
    (2) Make the following available for BOEM to inspect:
    (i) The area covered under a lease, ROW grant, or RUE grant;
    (ii) All improvements, structures, and fixtures on these areas; and
    (iii) All records of design, construction, operation, maintenance, 
repairs, or investigations on or related to the area.
    (b) You must retain these records in paragraph (a)(2)(iii) of this 
section until BOEM releases your financial assurance under Sec.  
585.534 and provide them to BOEM upon request, within the time period 
specified by BOEM.
    (c) You must demonstrate to the inspector how you are in compliance 
with your Safety Management System.

Sec.  585.823  Will BOEM reimburse me for my expenses related to 
inspections?

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

Sec.  585.824  How must I conduct self-inspections?

    (a) You must develop a comprehensive annual self-inspection plan 
covering all of your facilities. You must keep this plan wherever you 
keep your records and make it available to BOEM inspectors upon 
request. Your plan must specify:
    (1) The type, extent, and frequency of in-place inspections that 
you will conduct for both the above-water and the below-water 
structures of all facilities and pertinent components of the mooring 
systems for any floating facilities; and
    (2) How you are monitoring the corrosion protection for both the 
above-water and below-water structures.
    (b) You must submit a report annually to us no later than November 
1 that must include:
    (1) A list of facilities inspected in the preceding 12 months;
    (2) The type of inspection employed, (i.e., visual, magnetic 
particle, ultrasonic testing); and
    (3) A summary of the inspection indicating what repairs, if any, 
were needed and the overall structural condition of the facility.

Sec.  585.825  When must I assess my facilities?

    (a) You must perform an assessment of the structure, when needed, 
based on the platform assessment initiators listed in sections 17.2.1-
17.2.5 of API RP 2A-WSD, Recommended Practice for Planning, Designing 
and Constructing Fixed Offshore Platforms--Working Stress Design (as 
incorporated by reference in Sec.  585.115).
    (b) You must initiate mitigation actions for structures that do not 
pass the assessment process of API RP 2A-WSD.
    (c) You must perform other assessments as required by BOEM.

Sec. Sec.  585.826-585.829   [Reserved]

Incident Reporting and Investigation

Sec.  585.830  What are my incident reporting requirements?

    (a) You must report all incidents listed in Sec.  585.831 to BOEM, 
according to the reporting requirements for these incidents in 
Sec. Sec.  585.832 and 585.833.
    (b) These reporting requirements apply to incidents that occur on 
the area covered by your lease or grant under this part and that are 
related to activities resulting from the exercise of your rights under 
your lease or grant under this part.
    (c) Nothing in this subpart relieves you from providing notices and 
reports of incidents that may be required by other regulatory agencies.
    (d) You must report all spills of oil or other liquid pollutants in 
accordance with 30 CFR 254.46.

Sec.  585.831  What incidents must I report, and when must I report 
them?

    (a) You must report the following incidents to us immediately via 
oral communication, and provide a written follow-up report (paper copy 
or electronically transmitted) within 15 business days after the 
incident:
    (1) Fatalities;
    (2) Incidents that require the evacuation of person(s) from the 
facility to shore or to another offshore facility;
    (3) Fires and explosions;
    (4) Collisions that result in property or equipment damage greater 
than $25,000 (Collision means the act of a moving vessel (including an 
aircraft) striking another vessel, or striking a stationary vessel or 
object. Property or equipment damage means the cost of labor and 
material to restore all affected items to their condition before the 
damage, including, but not limited to, the OCS facility, a vessel, a 
helicopter, or the equipment. It does not include the cost of salvage, 
cleaning, dry docking, or demurrage);
    (5) Incidents involving structural damage to an OCS facility that 
is severe enough so that activities on the facility cannot continue 
until repairs are made;
    (6) Incidents involving crane or personnel/material handling 
activities, if they result in a fatality, injury, structural damage, or 
significant environmental damage;
    (7) Incidents that damage or disable safety systems or equipment 
(including firefighting systems);
    (8) Other incidents resulting in property or equipment damage 
greater than $25,000; and
    (9) Any other incidents involving significant environmental damage, 
or harm.
    (b) You must provide a written report of the following incidents to 
us within 15 days after the incident:
    (1) Any injuries that result in the injured person not being able 
to return to work or to all of their normal duties the day after the 
injury occurred; and
    (2) All incidents that require personnel on the facility to muster 
for evacuation for reasons not related to weather or drills.

Sec.  585.832  How do I report incidents requiring immediate 
notification?

    For an incident requiring immediate notification under Sec.  
585.831(a), you must notify BOEM verbally after aiding the injured and 
stabilizing the situation. Your verbal communication must provide the 
following information:
    (a) Date and time of occurrence;
    (b) Identification and contact information for the lessee, grant 
holder, or operator;
    (c) Contractor, and contractor representative's name and telephone 
number (if a contractor is involved in the incident or injury/
fatality);
    (d) Lease number, OCS area, and block;
    (e) Platform/facility name and number, or cable or pipeline segment 
number;
    (f) Type of incident or injury/fatality;
    (g) Activity at time of incident; and
    (h) Description of the incident, damage, or injury/fatality.

Sec.  585.833  What are the reporting requirements for incidents 
requiring written notification?

    (a) For any incident covered under Sec.  585.831, you must submit a 
written report within 15 days after the incident to BOEM. The report 
must contain the following information:

[[Page 64776]]

    (1) Date and time of occurrence;
    (2) Identification and contact information for each lessee, grant 
holder, or operator;
    (3) Name and telephone number of the contractor and the 
contractor's representative, if a contractor is involved in the 
incident or injury;
    (4) Lease number, OCS area, and block;
    (5) Platform/facility name and number, or cable or pipeline segment 
number;
    (6) Type of incident or injury;
    (7) Activity at time of incident;
    (8) Description of incident, damage, or injury (including days away 
from work, restricted work, or job transfer), and any corrective action 
taken; and
    (9) Property or equipment damage estimate (in U.S. dollars).
    (b) You may submit a report or form prepared for another agency in 
lieu of the written report required by paragraph (a) of this section if 
the report or form contains all required information.
    (c) BOEM may require you to submit additional information about an 
incident on a case-by-case basis.

Subpart I--Decommissioning

Decommissioning Obligations and Requirements

Sec.  585.900  Who must meet the decommissioning obligations in this 
subpart?

    (a) Lessees are jointly and severally responsible for meeting 
decommissioning obligations for facilities on their leases, including 
all obstructions, as the obligations accrue and until each obligation 
is met.
    (b) Grant holders are jointly and severally liable for meeting 
decommissioning obligations for facilities on their grant, including 
all obstructions, as the obligations accrue and until each obligation 
is met.

Sec.  585.901  When do I accrue decommissioning obligations?

    You accrue decommissioning obligations when you are or become a 
lessee or grant holder, and you either install, construct, or acquire 
by a BOEM-approved assignment a facility, cable, or pipeline, or you 
create an obstruction to other uses of the OCS.

Sec.  585.902  What are the general requirements for decommissioning 
for facilities authorized under my SAP, COP, or GAP?

    (a) Except as otherwise authorized by BOEM under Sec.  585.909, 
within 2 years following termination of a lease or grant, you must:
    (1) Remove or decommission all facilities, projects, cables, 
pipelines, and obstructions;
    (2) Clear the seafloor of all obstructions created by activities on 
your lease, including your project easement, or grant, as required by 
the BOEM.
    (b) Before decommissioning the facilities under your SAP, COP, or 
GAP, you must submit a decommissioning application and receive approval 
from the BOEM.
    (c) The approval of the decommissioning concept in the SAP, COP, or 
GAP is not an approval of a decommissioning application. However, you 
may submit your complete decommissioning application simultaneously 
with the SAP, COP, or GAP so that it may undergo appropriate technical 
and regulatory reviews at that time.
    (d) Following approval of your decommissioning application, you 
must submit a decommissioning notice under Sec.  585.908 to BOEM at 
least 60 days before commencing decommissioning activities.
    (e) If you, your subcontractors, or any agent acting on your behalf 
discover any archaeological resource while conducting decommissioning 
activities, you must immediately halt bottom-disturbing activities 
within 1,000 feet of the discovery and report the discovery to us 
within 72 hours. We will inform you how to conduct investigations to 
determine if the resource is significant and how to protect it. You, 
your subcontractors, or any agent acting on your behalf must keep the 
location of the discovery confidential and must not take any action 
that may adversely affect the archaeological resource until we have 
made an evaluation and told you how to proceed.
    (f) Provide BOEM with documentation of any coordination efforts you 
have made with the affected States, local, and Tribal governments.

Sec.  585.903  What are the requirements for decommissioning FERC-
licensed hydrokinetic facilities?

    You must comply with the decommissioning requirements in your BOEM-
issued lease. If you fail to comply with the decommissioning 
requirements of your lease then:
    (a) BOEM may call for the forfeiture of your bond or other 
financial assurance;
    (b) You remain liable for removal or disposal costs and responsible 
for accidents or damages that might result from such failure; and
    (c) BOEM may take enforcement action under Sec.  585.400 of this 
part.

Sec.  585.904  Can I request a departure from the decommissioning 
requirements?

    You may request a departure from the decommissioning requirements 
under Sec.  585.103.

Decommissioning Applications

Sec.  585.905  When must I submit my decommissioning application?

    You must submit your decommissioning application upon the earliest 
of the following dates:
    (a) 2 years before the expiration of your lease.
    (b) 90 days after completion of your commercial activities on a 
commercial lease.
    (c) 90 days after completion of your approved activities under a 
limited lease on a ROW grant or RUE grant.
    (d) 90 days after cancellation, relinquishment, or other 
termination of your lease or grant.

Sec.  585.906  What must my decommissioning application include?

    You must provide one paper copy and one electronic copy of the 
application. Include the following information in the application, as 
applicable.
    (a) Identification of the applicant including:
    (1) Lease operator, ROW grant holder, or RUE grant holder;
    (2) Address;
    (3) Contact person and telephone number; and
    (4) Shore base.
    (b) Identification and description of the facilities, cables, or 
pipelines you plan to remove or propose to leave in place, as provided 
in Sec.  585.909.
    (c) A proposed decommissioning schedule for your lease, ROW grant, 
or RUE grant, including the expiration or relinquishment date and 
proposed month and year of removal.
    (d) A description of the removal methods and procedures, including 
the types of equipment, vessels, and moorings (i.e., anchors, chains, 
lines, etc.) you will use.
    (e) A description of your site clearance activities.
    (f) Your plans for transportation and disposal (including as an 
artificial reef) or salvage of the removed facilities, cables, or 
pipelines and any required approvals.
    (g) A description of those resources, conditions, and activities 
that could be affected by or could affect your proposed decommissioning 
activities. The description must be as detailed as necessary to assist 
BOEM in complying with the NEPA and other relevant Federal laws.
    (h) The results of any recent biological surveys conducted in the 
vicinity of the

[[Page 64777]]

structure and recent observations of turtles or marine mammals at the 
structure site.
    (i) Mitigation measures you will use to protect archaeological and 
sensitive biological features during removal activities.
    (j) A description of measures you will take to prevent unauthorized 
discharge of pollutants, including marine trash and debris, into the 
offshore waters.
    (k) A statement of whether or not you will use divers to survey the 
area after removal to determine any effects on marine life.

Sec.  585.907  How will BOEM process my decommissioning application?

    (a) Based upon your inclusion of all the information required by 
Sec.  585.906, BOEM will compare your decommissioning application with 
the decommissioning general concept in your approved SAP, COP, or GAP 
to determine what technical and environmental reviews are needed.
    (b) You will likely have to revise your SAP, COP, or GAP, and BOEM 
will begin the appropriate NEPA analysis and other regulatory reviews 
as required, if BOEM determines that your decommissioning application 
would:
    (1) Result in a significant change in the impacts previously 
identified and evaluated in your SAP, COP, or GAP;
    (2) Require any additional Federal permits; or
    (3) Propose activities not previously identified and evaluated in 
your SAP, COP, or GAP.
    (c) During the review process, we may request additional 
information if we determine that the information provided is not 
sufficient to complete the review and approval process.
    (d) Upon completion of the technical and environmental reviews, we 
may approve, approve with conditions, or disapprove your 
decommissioning application.
    (e) If BOEM disapproves your decommissioning application, you must 
resubmit your application to address the concerns identified by BOEM.

Sec.  585.908  What must I include in my decommissioning notice?

    (a) The decommissioning notice is distinct from your 
decommissioning application and may only be submitted following 
approval of your decommissioning application, as described in 
Sec. Sec.  585.905 through 585.907. You must submit a decommissioning 
notice at least 60 days before you plan to begin decommissioning 
activities.
    (b) Your decommissioning notice must include:
    (1) A description of any changes to the approved removal methods 
and procedures in your approved decommissioning application, including 
changes to the types of vessels and equipment you will use; and
    (2) An updated decommissioning schedule.
    (c) We will review your decommissioning notice and may require you 
to resubmit a decommissioning application if BOEM determines that your 
decommissioning activities would:
    (1) Result in a significant change in the impacts previously 
identified and evaluated;
    (2) Require any additional Federal permits; or
    (3) Propose activities not previously identified and evaluated.

Facility Removal

Sec.  585.909  When may BOEM authorize facilities to remain in place 
following termination of a lease or grant?

    (a) In your decommissioning application, you may request that 
certain facilities authorized in your lease or grant remain in place 
for other activities authorized in this part, elsewhere in this 
subchapter, or by other applicable Federal laws.
    (b) BOEM may approve such requests on a case-by-case basis 
considering the following:
    (1) Potential impacts to the marine environment;
    (2) Competing uses of the OCS;
    (3) Impacts on marine safety and National defense;
    (4) Maintenance of adequate financial assurance; and
    (5) Other factors determined by the Director.
    (c) Except as provided in paragraph (d) of this section, if BOEM 
authorizes facilities to remain in place, the former lessee or grantee 
under this part remains jointly and severally liable for 
decommissioning the facility unless satisfactory evidence is provided 
to BOEM showing that another party has assumed that responsibility and 
has secured adequate financial assurances.
    (d) In your decommissioning application, you may request that 
certain facilities authorized in your lease or grant be converted to an 
artificial reef or otherwise toppled in place. BOEM will evaluate all 
such requests.

Sec.  585.910  What must I do when I remove my facility?

    (a) You must remove all facilities to a depth of 15 feet below the 
mudline, unless otherwise authorized by BOEM.
    (b) Within 60 days after you remove a facility, you must verify to 
BOEM that you have cleared the site.

Sec.  585.911  [Reserved]

Decommissioning Report

Sec.  585.912  After I remove a facility, cable, or pipeline, what 
information must I submit?

    Within 60 days after you remove a facility, cable, or pipeline, you 
must submit a written report to BOEM that includes the following:
    (a) A summary of the removal activities, including the date they 
were completed;
    (b) A description of any mitigation measures you took; and
    (c) If you used explosives, a statement signed by your authorized 
representative that certifies that the types and amount of explosives 
you used in removing the facility were consistent with those in the 
approved decommissioning application.

Compliance With an Approved Decommissioning Application

Sec.  585.913  What happens if I fail to comply with my approved 
decommissioning application?

    If you fail to comply with your approved decommissioning plan or 
application:
    (a) BOEM may call for the forfeiture of your bond or other 
financial assurance;
    (b) You remain liable for removal or disposal costs and responsible 
for accidents or damages that might result from such failure; and
    (c) BOEM may take enforcement action under Sec.  585.400.

Subpart J--Rights of Use and Easement for Energy- and Marine-
Related Activities Using Existing OCS Facilities

Regulated Activities

Sec.  585.1000  What activities does this subpart regulate?

    (a) This subpart provides the general provisions for authorizing 
and regulating activities that use (or propose to use) an existing OCS 
facility for energy- or marine-related purposes, that are not otherwise 
authorized under any other part of this subchapter or any other 
applicable Federal statute. Activities authorized under any other part 
of this subchapter or under any other Federal law that use (or propose 
to use) an existing OCS facility are not subject to this subpart.
    (b) BOEM will issue an Alternate Use RUE for activities authorized 
under this subpart.

[[Page 64778]]

    (c) At the discretion of the Director, an Alternate Use RUE may:
    (1) Permit alternate use activities to occur at an existing 
facility that is currently in use under an approved OCS lease; or
    (2) Limit alternate use activities at the existing facility until 
after previously authorized activities at the facility have ceased and 
the OCS lease terminates.

Sec. Sec.  585.1001-585.1003  [Reserved]

Requesting an Alternate Use RUE

Sec.  585.1004  What must I do before I request an Alternate Use RUE?

    If you are not the owner of the existing facility on the OCS and 
the lessee of the area in which the facility is located, you must 
contact the lessee and owner of the facility and reach a preliminary 
agreement as to the proposed activity for the use of the existing 
facility.

Sec.  585.1005  How do I request an Alternate Use RUE?

    To request an Alternate Use RUE, you must submit to BOEM all of the 
following:
    (a) The name, address, e-mail address, and phone number of an 
authorized representative.
    (b) A summary of the proposed activities for the use of an existing 
OCS facility, including:
    (1) The type of activities that would involve the use of the 
existing OCS facility;
    (2) A description of the existing OCS facility, including a map 
providing its location on the lease block;
    (3) The names of the owner of the existing OCS facility, the 
operator, the lessee, and any owner of operating rights on the lease at 
which the facility is located;
    (4) A description of additional structures or equipment that will 
be required to be located on or in the vicinity of the existing OCS 
facility in connection with the proposed activities;
    (5) A statement indicating whether any of the proposed activities 
are intended to occur before existing activities on the OCS facility 
have ceased; and
    (6) A statement describing how existing activities at the OCS 
facility will be affected if proposed activities are to occur at the 
same time as existing activities at the OCS facility.
    (c) A statement affirming that the proposed activities sought to be 
approved under this subpart are not otherwise authorized by other 
provisions in this subchapter or any other Federal law.
    (d) Evidence that you meet the requirements of Sec.  585.106, as 
required by Sec.  585.107.
    (e) The signatures of the applicant, the owner of the existing OCS 
facility, and the lessee of the area in which the existing facility is 
located.

Sec.  585.1006  How will BOEM decide whether to issue an Alternate Use 
RUE?

    (a) We will consider requests for an Alternate Use RUE on a case-
by-case basis. In considering such requests, we will consult with 
relevant Federal agencies and evaluate whether the proposed activities 
involving the use of an existing OCS facility can be conducted in a 
manner that:
    (1) Ensures safety and minimizes adverse effects to the coastal and 
marine environments, including their physical, atmospheric, and 
biological components, to the extent practicable;
    (2) Does not inhibit or restrain orderly development of OCS mineral 
or energy resources; and
    (3) Avoids serious harm or damage to, or waste of, any natural 
resource (including OCS mineral deposits and oil, gas, and sulphur 
resources in areas leased or not leased), any life (including fish and 
other aquatic life), or property (including sites, structures, or 
objects of historical or archaeological significance);
    (4) Is otherwise consistent with subsection 8(p) of the OCS Lands 
Act; and
    (5) BOEM can effectively regulate.
    (b) Based on the evaluation that we perform under paragraph (a) of 
this section, the BOEM may authorize or reject, or authorize with 
modifications or stipulations, the proposed activity.

Sec.  585.1007  What process will BOEM use for competitively offering 
an Alternate Use RUE?

    (a) An Alternate Use RUE must be issued on a competitive basis 
unless BOEM determines, after public notice of the proposed Alternate 
Use RUE, that there is no competitive interest.
    (b) We will issue a public notice in the Federal Register to 
determine if there is competitive interest in using the proposed 
facility for alternate use activities. BOEM will specify a time period 
for members of the public to express competitive interest.
    (c) If we receive indications of competitive interest within the 
published timeframe, we will proceed with a competitive offering. As 
part of such competitive offering, each competing applicant must submit 
a description of the types of activities proposed for the existing 
facility, as well as satisfactory evidence that the competing applicant 
qualifies to hold a lease or grant on the OCS, as required in 
Sec. Sec.  585.106 and 585.107, by a date we specify. We may request 
additional information from competing applicants, as necessary, to 
adequately evaluate the competing proposals.
    (d) We will evaluate all competing proposals to determine whether:
    (1) The proposed activities are compatible with existing activities 
at the facility; and
    (2) We have the expertise and resources available to regulate the 
activities effectively.
    (e) We will evaluate all proposals under the requirements of NEPA, 
CZMA, and other applicable laws.
    (f) Following our evaluation, we will select one or more acceptable 
proposals for activities involving the alternate use of an existing OCS 
facility, notify the competing applicants, and submit each acceptable 
proposal to the lessee and owner of the existing OCS facility. If the 
lessee and owner of the facility agree to accept a proposal, we will 
proceed to issue an Alternate Use RUE. If the lessee and owner of the 
facility are unwilling to accept any of the proposals that we deem 
acceptable, we will not issue an Alternate Use RUE.

Sec.  585.1008  [Reserved]

Sec.  585.1009  [Reserved]

Alternate Use RUE Administration

Sec.  585.1010  How long may I conduct activities under an Alternate 
Use RUE?

    (a) We will establish on a case-by-case basis, and set forth in the 
Alternate Use RUE, the length of time for which you are authorized to 
conduct activities approved in your Alternate Use RUE instrument.
    (b) In establishing this term, BOEM will consider the size and 
scale of the proposed alternate use activities, the type of alternate 
use activities, and any other relevant considerations.
    (c) BOEM may authorize renewal of Alternate Use RUEs at its 
discretion.

Sec.  585.1011  What payments are required for an Alternate Use RUE?

    We will establish rental or other payments for an Alternate Use RUE 
on a case-by-case basis, as set forth in the Alternate Use RUE grant, 
depending on our assessment of the following factors:
    (a) The effect on the original OCS Lands Act approved activity;
    (b) The size and scale of the proposed alternate use activities;
    (c) The income, if any, expected to be generated from the proposed 
alternate use activities; and
    (d) The type of alternate use activities.

[[Page 64779]]

Sec.  585.1012  What financial assurance is required for an Alternate 
Use RUE?

    (a) The holder of an Alternate Use RUE will be required to secure 
financial assurances in an amount determined by BOEM that is sufficient 
to cover all obligations under the Alternate Use RUE, including 
decommissioning obligations, and must retain such financial assurance 
amounts until all obligations have been fulfilled, as determined by 
BOEM.
    (b) We may revise financial assurance amounts, as necessary, to 
ensure that there is sufficient financial assurance to secure all 
obligations under the Alternate Use RUE.
    (c) We may reduce the amount of the financial assurance that you 
must retain if it is not necessary to cover existing obligations under 
the Alternate Use RUE.

Sec.  585.1013  Is an Alternate Use RUE assignable?

    (a) BOEM may authorize assignment of an Alternate Use RUE.
    (b) To request assignment of an Alternate Use RUE, you must submit 
a written request for assignment that includes the following 
information:
    (1) BOEM-assigned Alternate Use RUE number;
    (2) The names of both the assignor and the assignee, if applicable;
    (3) The names and telephone numbers of the contacts for both the 
assignor and the assignee;
    (4) The names, titles, and signatures of the authorizing officials 
for both the assignor and the assignee;
    (5) A statement affirming that the owner of the existing OCS 
facility and lessee of the lease in which the facility is located 
approve of the proposed assignment and assignee;
    (6) A statement that the assignee agrees to comply with and to be 
bound by the terms and conditions of the Alternate Use RUE;
    (7) Evidence required by Sec.  585.107 that the assignee satisfies 
the requirements of Sec.  585.106; and
    (8) A statement on how the assignee will comply with the financial 
assurance requirements set forth in the Alternate Use RUE.
    (c) The assignment takes effect on the date we approve your 
request.
    (d) The assignor is liable for all obligations that accrue under an 
Alternate Use RUE before the date we approve your assignment request. 
An assignment approval by BOEM does not relieve the assignor of 
liability for accrued obligations that the assignee, or a subsequent 
assignee, fails to perform.
    (e) The assignee and each subsequent assignee are liable for all 
obligations that accrue under an Alternate Use RUE after the date we 
approve the assignment request.

Sec.  585.1014  When will BOEM suspend an Alternate Use RUE?

    (a) BOEM may suspend an Alternate Use RUE if:
    (1) Necessary to comply with judicial decrees;
    (2) Continued activities pursuant to the Alternate Use RUE pose an 
imminent threat of serious or irreparable harm or damage to natural 
resources; life (including human and wildlife); property; the marine, 
coastal, or human environment; or sites, structures, or objects of 
historical or archaeological significance;
    (3) The suspension is necessary for reasons of National security or 
defense; or
    (4) We have suspended or temporarily prohibited operation of the 
existing OCS facility that is subject to the Alternate Use RUE, and 
have determined that continued activities under the Alternate Use RUE 
are unsafe or cause undue interference with the operation of the 
original OCS Lands Act approved activity.
    (b) A suspension will extend the term of your Alternate Use RUE 
grant for the period of the suspension.

Sec.  585.1015  How do I relinquish an Alternate Use RUE?

    (a) You may voluntarily surrender an Alternate Use RUE by 
submitting a written request to us that includes the following:
    (1) The name, address, e-mail address, and phone number of an 
authorized representative;
    (2) The reason you are requesting relinquishment of the Alternate 
Use RUE;
    (3) BOEM-assigned Alternate Use RUE number;
    (4) The name of the associated OCS facility, its owner, and the 
lessee for the lease in which the OCS facility is located;
    (5) The name, title, and signature of your authorizing official 
(which must match exactly the name, title, and signature in the BOEM 
qualification records); and
    (6) A statement that you will adhere to the decommissioning 
requirements in the Alternate Use RUE.
    (b) We will not approve your relinquishment request until you have 
paid all outstanding rentals (or other payments) and fines.
    (c) The relinquishment takes effect on the date we approve your 
request.

Sec.  585.1016  When will an Alternate Use RUE be cancelled?

    The Secretary may cancel an Alternate Use RUE if it is determined, 
after notice and opportunity to be heard:
    (a) You no longer qualify to hold an Alternate Use RUE;
    (b) You failed to provide any additional financial assurance 
required by BOEM, replace or provide additional coverage for a de-
valued bond, or replace a lapsed or forfeited bond within the 
prescribed time period;
    (c) Continued activity under the Alternate Use RUE is likely to 
cause serious harm or damage to natural resources; life (including 
human and wildlife); property; the marine, coastal, or human 
environment; or sites, structures, or objects of historical or 
archaeological significance;
    (d) Continued activity under the Alternate Use RUE is determined to 
be adversely impacting the original OCS Lands Act approved activities 
on the existing OCS facility;
    (e) You failed to comply with any of the terms and conditions of 
your approved Alternate Use RUE or your approved plan; or
    (f) You otherwise failed to comply with applicable laws or 
regulations.

Sec.  585.1017  [Reserved]

Decommissioning an Alternate Use RUE

Sec.  585.1018  Who is responsible for decommissioning an OCS facility 
subject to an Alternate Use RUE?

    (a) The holder of an Alternate Use RUE is responsible for all 
decommissioning obligations that accrue following the issuance of the 
Alternate Use RUE and which pertain to the Alternate Use RUE.
    (b) The lessee under the lease originally issued under 30 CFR part 
250 will remain responsible for decommissioning obligations that 
accrued before issuance of the Alternate Use RUE, as well as for 
decommissioning obligations that accrue following issuance of the 
Alternate Use RUE to the extent associated with continued activities 
authorized under other parts of this title.

Sec.  585.1019  What are the decommissioning requirements for an 
Alternate Use RUE?

    (a) Decommissioning requirements will be determined by BOEM on a 
case-by-case basis, and will be included in the terms of each Alternate 
Use RUE.
    (b) Decommissioning activities must be completed within 1 year of 
termination of the Alternate Use RUE.
    (c) If you fail to satisfy all decommissioning requirements within

[[Page 64780]]

the prescribed time period, we will call for the forfeiture of your 
bond or other financial guarantee, and you will remain liable for all 
accidents or damages that might result from such failure.

SUBCHAPTER C--APPEALS

PART 590--APPEAL PROCEDURES

Subpart A--Offshore Minerals Management Appeal Procedures
Sec.
590.1 What is the purpose of this subpart?
590.2 Who may appeal?
590.3 What is the time limit for filing an appeal?
590.4 How do I file an appeal?
590.5 Can I obtain an extension for filing my Notice of Appeal?
590.6 Are informal resolutions permitted?
590.7 Do I have to comply with the decision or order while my appeal 
is pending?
590.8 How do I exhaust my administrative remedies?
Subpart B--[Reserved]

    Authority: 5 U.S.C. 301 et seq.; 43 U.S.C. 1331

Subpart A--Offshore Minerals Management Appeal Procedures

Sec.  590.1  What is the purpose of this subpart?

    The purpose of this subpart is to explain the procedures for 
appeals of Bureau of Ocean Energy Management (BOEM) Offshore Minerals 
Management (OMM) decisions and orders issued under subchapter C.

Sec.  590.2  Who may appeal?

    If you are adversely affected by an OMM official's final decision 
or order issued under 30 CFR chapter V, subchapter C, you may appeal 
that decision or order to the Interior Board of Land Appeals (IBLA). 
Your appeal must conform with the procedures found in this subpart and 
43 CFR part 4, subpart E. A request for reconsideration of a BOEM 
decision concerning a lease bid, authorized in 30 CFR parts 
556.47(e)(3), 581.21(a)(1), or 585.118(c), is not subject to the 
procedures found in this part.

Sec.  590.3  What is the time limit for filing an appeal?

    You must file your appeal within 60 days after you receive OMM's 
final decision or order. The 60-day time period applies rather than the 
time period provided in 43 CFR 4.411(a). A decision or order is 
received on the date you sign a receipt confirming delivery or, if 
there is no receipt, the date otherwise documented.

Sec.  590.4  How do I file an appeal?

    For your appeal to be filed, BOEM must receive all of the following 
within 60 days after you receive the decision or order:
    (a) A written Notice of Appeal together with a copy of the decision 
or order you are appealing in the office of the OEMM officer that 
issued the decision or order. You cannot extend the 60-day period for 
that office to receive your Notice of Appeal; and
    (b) A nonrefundable processing fee of $150 paid with the Notice of 
Appeal.
    (1) You must pay electronically through Pay.gov at: https://www.pay.gov/paygov/, and you must include a copy of the Pay.gov 
confirmation receipt page with your Notice of Appeal.
    (2) You cannot extend the 60-day period for payment of the 
processing fee.

Sec.  590.5  Can I obtain an extension for filing my Notice of Appeal?

    You cannot obtain an extension of time to file the Notice of 
Appeal. See 43 CFR 4.411(c).

Sec.  590.6  Are informal resolutions permitted?

    (a) You may seek informal resolution with the issuing officer's 
next level supervisor during the 60-day period established in Sec.  
590.3.
    (b) Nothing in this subpart precludes resolution by settlement of 
any appeal or matter pending in the administrative process after the 
60-day period established in Sec.  590.3.

Sec.  590.7  Do I have to comply with the decision or order while my 
appeal is pending?

    (a) The decision or order is effective during the 60-day period for 
filing an appeal under Sec.  590.3 unless:
    (1) OMM notifies you that the decision or order, or some portion of 
it, is suspended during this period because there is no likelihood of 
immediate and irreparable harm to human life, the environment, any 
mineral deposit, or property; or
    (2) You post a surety bond under 30 CFR 550.1409 pending the appeal 
challenging an order to pay a civil penalty.
    (b) This section applies rather than 43 CFR 4.21(a) for appeals of 
OMM orders.
    (c) After you file your appeal, IBLA may grant a stay of a decision 
or order under 43 CFR 4.21(b); however, a decision or order remains in 
effect until IBLA grants your request for a stay of the decision or 
order under appeal.

Sec.  590.8  How do I exhaust my administrative remedies?

    (a) If you receive a decision or order issued under chapter V, 
subchapter C, you must appeal that decision or order to IBLA under 43 
CFR part 4, subpart E, to exhaust administrative remedies.
    (b) This section does not apply if the Assistant Secretary for Land 
and Minerals Management or the IBLA makes a decision or order 
immediately effective notwithstanding an appeal.

Subpart B--[Reserved]

[FR Doc. 2011-22675 Filed 9-29-11; 12:00 pm]
BILLING CODE 4310-MR-P
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